Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Jan. 31, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Entity Registrant Name | SYNERGY RESOURCES CORP | ||
Entity Central Index Key | 1,413,507 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,016 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 200,674,003 | ||
Entity Public Float | $ 1.3 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 18,615 | $ 66,499 |
Accounts receivable: | ||
Oil and natural gas sales | 25,728 | 12,527 |
Trade | 6,805 | 12,156 |
Commodity derivative assets | 297 | 6,572 |
Other current assets | 2,739 | 1,944 |
Total current assets | 54,184 | 99,698 |
Property and equipment: | ||
Unproved properties and land, not subject to depletion | 398,547 | 93,600 |
Proved properties, net of accumulated depletion | 424,082 | 411,291 |
Costs of wells in progress | 81,780 | 21,310 |
Oil and gas properties, net | 904,409 | 526,201 |
Other property and equipment, net | 4,327 | 646 |
Total property and equipment, net | 908,736 | 526,847 |
Cash held in escrow and other deposits | 18,248 | 0 |
Commodity derivative assets | 0 | 2,996 |
Goodwill | 40,711 | 40,711 |
Other assets | 2,234 | 2,364 |
Total assets | 1,024,113 | 672,616 |
Current liabilities: | ||
Accounts payable and accrued expenses | 52,453 | 36,573 |
Revenue payable | 16,557 | 13,603 |
Production taxes payable | 17,673 | 24,530 |
Asset retirement obligations | 2,683 | 0 |
Commodity derivative liabilities | 2,874 | 0 |
Total current liabilities | 92,240 | 74,706 |
Revolving credit facility | 0 | 78,000 |
Notes payable, net of issuance costs | 75,614 | 0 |
Asset retirement obligations | 13,775 | 13,400 |
Other liabilities | 1,745 | |
Total liabilities | 183,374 | 166,106 |
Commitments and contingencies (See Note16) | ||
Shareholders' equity: | ||
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding | 0 | 0 |
Common stock - $0.001 par value, 300,000,000 shares authorized: 200,647,572 and 110,033,601 shares issued and outstanding, respectively | 201 | 110 |
Additional paid-in capital | 1,148,998 | 595,671 |
Retained deficit | (308,460) | (89,271) |
Total shareholders' equity | 840,739 | 506,510 |
Total liabilities and shareholders' equity | $ 1,024,113 | $ 672,616 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value per share (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 300,000,000 | 300,000,000 |
Common stock, shares issued | 200,647,572 | 110,033,601 |
Common stock, shares outstanding | 110,033,601 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Income Statement [Abstract] | ||||
Oil and natural gas revenues | $ 34,138 | $ 107,149 | $ 124,843 | $ 104,219 |
Expenses: | ||||
Lease operating expenses | 5,812 | 19,949 | 15,017 | 7,991 |
Production taxes | 3,104 | 5,732 | 11,340 | 9,667 |
Depreciation, depletion, and accretion | 18,776 | 46,678 | 65,869 | 32,958 |
Full cost ceiling impairment | 125,230 | 215,223 | 16,000 | 0 |
Transportation commitment charge | 2,802 | 597 | 0 | 0 |
General and administrative | 17,875 | 30,545 | 18,995 | 10,139 |
Total expenses | 173,599 | 318,724 | 127,221 | 60,755 |
Operating (loss) income | (139,461) | (211,575) | (2,378) | 43,464 |
Other income (expense): | ||||
Commodity derivative gain (loss) | 6,482 | (7,750) | 32,256 | 321 |
Interest expense, net | 0 | 0 | (245) | 0 |
Interest income | 40 | 242 | 86 | 82 |
Total other income (expense) | 6,522 | (7,508) | 32,097 | 403 |
(Loss) Income before income taxes | (132,939) | (219,083) | 29,719 | 43,867 |
Income tax expense (benefit) | (10,007) | 106 | 11,677 | 15,014 |
Net (loss) income | $ (122,932) | $ (219,189) | $ 18,042 | $ 28,853 |
Net (loss) income per common share: | ||||
Basic (in dollars per share) | $ (1.14) | $ (1.26) | $ 0.19 | $ 0.38 |
Diluted (in dollars per share) | $ (1.14) | $ (1.26) | $ 0.19 | $ 0.37 |
Weighted-average shares outstanding: | ||||
Basic (in shares) | 107,789,554 | 173,774,035 | 94,628,665 | 76,214,737 |
Diluted (in shares) | 107,789,554 | 173,774,035 | 95,319,269 | 77,808,054 |
CONSOLIDATED STATEMENT OF CHANG
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Accumulated Earnings (Deficit) [Member] |
Balance at Aug. 31, 2013 | $ 203,220 | $ 71 | $ 216,383 | $ (13,234) |
Balance, shares at Aug. 31, 2013 | 70,587,723 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering, shares | 0 | |||
Shares issued for acquisition | $ 8,328 | $ 1 | 8,327 | |
Shares issued for acquisition, shares | 872,483 | 872,483 | ||
Shares issued in exchange for mineral assets | $ 2,856 | $ 0 | 2,856 | |
Shares issued in exchange for mineral assets, shares | 357,901 | 357,901 | ||
Shares issued for exercise of warrants | $ 35,634 | $ 6 | 35,628 | |
Shares issued for exercise of warrants, shares | 6,063,801 | |||
Shares issued under stock bonus plan and equity incentive plans | 1,201 | 1,201 | ||
Shares issued under stock bonus plan equity incentive plans, shares | 89,875 | |||
Shares issued for exercise of stock options | $ 0 | |||
Shares issued for exercise of stock options, shares | 61,000 | 27,299 | ||
Stock based compensation for options | $ 1,767 | 1,767 | ||
Stock based compensation for options, shares | 0 | |||
Payment of tax withholdings using withheld shares | (369) | (369) | ||
Net (loss) income | 28,853 | 28,853 | ||
Balance at Aug. 31, 2014 | 281,490 | $ 78 | 265,793 | 15,619 |
Balance, shares at Aug. 31, 2014 | 77,999,082 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering | $ 190,845 | $ 19 | 190,826 | |
Shares issued in equity offering, shares | 18,613,952 | 18,613,952 | ||
Shares issued for acquisition | $ 48,434 | $ 5 | 48,429 | |
Shares issued for acquisition, shares | 4,648,136 | 4,648,136 | ||
Shares issued in exchange for mineral assets | $ 11,787 | $ 1 | 11,786 | |
Shares issued in exchange for mineral assets, shares | 995,672 | 995,672 | ||
Shares issued for exercise of warrants | $ 15,370 | $ 2 | 15,368 | |
Shares issued for exercise of warrants, shares | 2,562,473 | |||
Shares issued under stock bonus plan and equity incentive plans | 2,950 | 2,950 | ||
Shares issued under stock bonus plan equity incentive plans, shares | 161,755 | |||
Shares issued for exercise of stock options | $ 0 | |||
Shares issued for exercise of stock options, shares | 258,000 | 118,272 | ||
Stock based compensation for options | $ 4,741 | 4,741 | ||
Stock based compensation for options, shares | 0 | |||
Payment of tax withholdings using withheld shares | (1,262) | (1,262) | ||
Net (loss) income | 18,042 | 18,042 | ||
Balance at Aug. 31, 2015 | $ 572,397 | $ 105 | 538,631 | 33,661 |
Balance, shares at Aug. 31, 2015 | 105,099,342 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering, shares | 0 | |||
Shares issued for acquisition | $ 49,839 | $ 4 | 49,835 | |
Shares issued for acquisition, shares | 4,418,413 | 4,418,413 | ||
Shares issued in exchange for mineral assets | $ 426 | $ 0 | 426 | |
Shares issued in exchange for mineral assets, shares | 37,051 | 37,051 | ||
Shares issued under stock bonus plan and equity incentive plans | $ 7,163 | $ 1 | 7,162 | |
Shares issued under stock bonus plan equity incentive plans, shares | 422,035 | |||
Shares issued for exercise of stock options | $ 0 | |||
Shares issued for exercise of stock options, shares | 188,000 | 56,760 | ||
Stock based compensation for options | $ 2,161 | 2,161 | ||
Stock based compensation for options, shares | 0 | |||
Payment of tax withholdings using withheld shares | (2,544) | (2,544) | ||
Net (loss) income | (122,932) | (122,932) | ||
Balance at Dec. 31, 2015 | $ 506,510 | $ 110 | 595,671 | (89,271) |
Balance, shares at Dec. 31, 2015 | 110,033,601 | 110,033,601 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued in equity offering | $ 543,411 | $ 90 | 543,321 | |
Shares issued in equity offering, shares | 90,275,000 | 90,275,000 | ||
Shares issued for acquisition, shares | 0 | |||
Shares issued in exchange for mineral assets, shares | 0 | |||
Shares issued under stock bonus plan and equity incentive plans | $ 4,232 | $ 1 | 4,231 | |
Shares issued under stock bonus plan equity incentive plans, shares | 321,101 | |||
Shares issued for exercise of stock options | $ 68 | 68 | ||
Shares issued for exercise of stock options, shares | 20,000 | 17,870 | ||
Stock based compensation for options | $ 5,417 | 5,417 | ||
Stock-based compensation for performance-vested stock units | 1,047 | 1,047 | ||
Payment of tax withholdings using withheld shares | (757) | (757) | ||
Net (loss) income | (219,189) | (219,189) | ||
Balance at Dec. 31, 2016 | $ 840,739 | $ 201 | $ 1,148,998 | $ (308,460) |
Balance, shares at Dec. 31, 2016 | 200,647,572 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Cash flows from operating activities: | ||||
Net (loss) income | $ (122,932) | $ (219,189) | $ 18,042 | $ 28,853 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||
Depletion, depreciation, and accretion | 18,776 | 46,678 | 65,869 | 32,958 |
Full cost ceiling impairment | 125,230 | 215,223 | 16,000 | 0 |
Provision for deferred taxes | (10,007) | 0 | 11,679 | 15,014 |
Stock-based compensation | 8,431 | 9,491 | 7,691 | 2,968 |
Total (gain) loss on commodity derivative contracts | (6,482) | 7,750 | (32,256) | (321) |
Cash settlements on commodity derivative contracts | 1,954 | 5,374 | 31,721 | (2,138) |
Cash premiums paid for commodity derivative contracts | (956) | 0 | (4,117) | 0 |
Changes in operating assets and liabilities: | ||||
Accounts receivable | 5,696 | (13,063) | 3,446 | (20,311) |
Accounts payable and accrued expenses | 3,954 | 2,283 | (2,307) | 1,246 |
Revenue payable | (5,441) | 2,254 | 4,557 | 8,406 |
Production taxes payable | 3,631 | (7,095) | 5,121 | 8,099 |
Other | (1,782) | (1,018) | (359) | 131 |
Net cash provided by operating activities | 20,072 | 48,688 | 125,087 | 74,905 |
Cash flows from investing activities: | ||||
Acquisitions of oil and gas properties and leaseholds | (37,150) | (511,173) | (82,584) | (52,066) |
Capital expenditures for drilling and completion activities | (41,581) | (119,571) | (186,135) | (97,225) |
Other capital expenditures | (5,811) | (7,044) | (6,375) | (2,216) |
Land and other property and equipment | (395) | (5,478) | (714) | (4,095) |
Short-term investments | 0 | 0 | 0 | 60,018 |
Cash held in escrow | 0 | (18,219) | 0 | 0 |
Net proceeds from sales of oil and gas properties and land | 0 | 25,350 | 6,239 | 704 |
Net cash used in investing activities | (84,937) | (636,135) | (269,569) | (94,880) |
Cash flows from financing activities: | ||||
Proceeds from equity offerings | 0 | 565,398 | 200,100 | 0 |
Offering costs | 0 | (21,987) | (9,255) | 0 |
Proceeds from exercise of warrants and employee exercise of stock options | 0 | 68 | 15,370 | 35,634 |
Payment of employee payroll taxes in connection with shares withheld | (2,544) | (757) | (1,262) | (369) |
Proceeds from revolving credit facility | 0 | 55,000 | 186,000 | 0 |
Principal repayments on revolving credit facility | 0 | (133,000) | (145,000) | 0 |
Proceeds from issuance of notes payable | 0 | 80,000 | 0 | 0 |
Financing fees on issuance of notes payable and amendments to revolving credit facility | 0 | (5,159) | (2,316) | 0 |
Net cash provided by (used in) financing activities | (2,544) | 539,563 | 243,637 | 35,265 |
Net (decrease) increase in cash and equivalents | (67,409) | (47,884) | 99,155 | 15,290 |
Cash and equivalents at beginning of period | 133,908 | 66,499 | 34,753 | 19,463 |
Cash and equivalents at end of period | $ 66,499 | $ 18,615 | $ 133,908 | $ 34,753 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Summary of Significant Accounting Policies | Organization and Summary of Significant Accounting Policies Organization : Synergy Resources Corporation is engaged in oil and gas acquisition, exploration, development, and production activities, primarily in the D-J Basin of Colorado. The Company’s common stock is listed and traded on the NYSE MKT under the symbol “SYRG.” Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiary. All significant intercompany balances and transactions have been eliminated in consolidation. The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Change of Year-End: On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year. Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates. Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. As of December 31, 2016, the Company has placed $18.2 million in escrow to be released upon the second closing of the GC Acquisition. Please refer to Note 3 , Acquisitions and Divestitures, for further information. Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the year ended December 31, 2016 , the Company recognized ceiling test impairments totaling $215.2 million . The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves. Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 10 for additional information. Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information. Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment and software, office leasehold improvements, and office furniture and equipment) is stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment is depreciated under the straight-line method using estimated useful lives ranging from three to five years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its support equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands): As of December 31, 2016 2015 Trade accounts payable $ 786 $ 3,046 Accrued well costs 42,779 32,123 Accrued G&A 4,292 1,404 Accrued other 4,596 — 52,453 36,573 Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under ASC 805, Business Combinations . Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31 st . During 2016, we changed the date of our annual goodwill impairment assessment to October 1 st . With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. For purposes of assessing goodwill, the Company only has one reporting unit. As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016. We also performed our annual goodwill impairment test as of October 1, 2016. Neither of these tests resulted in an impairment. For both tests, the Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period. Oil and Natural Gas Sales: The Company derives revenue primarily from the sale of oil and natural gas produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil and natural gas revenue (“major customers”) for each of the periods presented are shown in the following table: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Company A 20% 15% 11% 13% Company B 20% * * * Company C 16% * * * Company D 13% * * * Company E * 57% 65% 54% Company F * 12% * * * less than 10% Based on the current demand for oil and natural gas, the availability of other buyers and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and natural gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer. Accounts receivable consist primarily of trade receivables from oil and natural gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table: As of December 31, 2016 2015 Company A 43% * Company B 23% 13% Company C 10% * Company D * 13% Company E * 13% * less than 10% The Company operates exclusively within the United States of America and, except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry. Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities. Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation. The compensation is recognized over the vesting period of the grant. See Note 13 for additional information. Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before December 31, 2016 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2016 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 15 for further information. Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 8 . Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations. Recently Adopted Accounting Pronouncements: On January 2017, the FASB issued Accounting Standards Update ("ASU") 2017-01, "Clarifying the Definition of a Business" ("ASU 2017-01"), which clarifies the definition of a business in ASC 805. The amendments narrow the definition of a business and provide a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. Specifically, ASU 2017-01: i) provides a “screen” for determining when a set is not a business. The screen requires a determination that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business; ii) specifies that if the screen’s threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs and provides a framework to help entities evaluate whether both an input and a substantive process are present; iii) it removes the evaluation of whether a market participant could replace the missing elements; and iv) narrows the definition of the term “output.” ASU 2017-01 is effective in annual periods beginning after December 15, 2017, including interim periods therein. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted for transactions (i.e., acquisitions or dispositions) that occurred before the issuance date or effective date of the standard if the transactions were not reported in financial statements that have been issued or made available for issuance. We elected to early adopt this pronouncement effective October 1, 2016. As a result of adopting this pronouncement, we accounted for certain transactions as asset acquisitions which would have qualified as business combinations had we not adopted the standard. Recent Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, which must apply the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We plan to adopt this pronouncement effective January 1, 2017. Upon adoption of this standard, we will no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we will account for forfeitures when they occur. We will apply this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.3 million to retained earnings as of the date of adoption. The adoption of the other provisions is not expected to materially impact the consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. Currently, we have not identified any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of these ASUs as pertinent to certain sales contracts and in particular as they relates to disclosure requirements. There have been various updates issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations or cash flows. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2016 2015 Oil and gas properties, full cost method: Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs $ 392,561 $ 89,122 Land 5,986 4,478 Subtotal, unproved properties and land 398,547 93,600 Costs of wells in progress 81,780 21,310 Costs of proved properties: Producing and non-producing 969,239 691,659 Less, accumulated depletion and full cost ceiling impairments (545,157 ) (280,368 ) Subtotal, proved properties, net 424,082 411,291 Costs of other property and equipment: Other property and equipment 5,063 1,270 Less, accumulated depreciation (736 ) (624 ) Subtotal, other property and equipment, net 4,327 646 Total property and equipment, net $ 908,736 $ 526,847 The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. As a result of these periodic reviews, the Company concluded that its net capitalized costs for oil and gas properties exceeded the ceiling amount, resulting in the recognition of ceiling test impairments totaling $215.2 million during the year ended December 31, 2016 . During the four months ended December 31, 2015 and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $125.2 million and $16.0 million , respectively. No such ceiling test impairments were recognized during the year ended August 31, 2014. The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or abandoned. Unproved properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2016, these reviews indicated that the estimated carrying values of such assets exceeded fair values. Therefore, the Company recorded impairments of $18.9 million , and these costs were moved into the full cost pool and subject to the aforementioned ceiling test. No such impairments were recognized during the four months ended December 31, 2015 or the year ended August 31, 2014. However, during the year ended August 31, 2015, the Company recorded impairments of $15.4 million related to the fair value of its unproved properties. Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Capitalized overhead $ 7,074 $ 1,091 $ 2,049 $ 1,230 Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Acquisition of property: Unproved $ 365,548 $ 38,779 $ 32,701 $ 15,002 Proved 152,363 51,085 51,400 33,795 Exploration costs 43,154 23,697 146,892 43,089 Development costs 87,782 17,742 4,957 111,238 Other property and equipment 7,506 395 741 9,315 Capitalized interest, capitalized G&A, and other 18,744 4,415 7,051 1,610 Total costs incurred $ 675,097 $ 136,113 $ 243,742 $ 214,049 Capitalized Costs Excluded from Depletion: The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2016 (in thousands): Period Incurred Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, Total as of December 31, 2016 2015 2014 2013 and Prior Unproved leasehold acquisition costs $ 349,777 $ 37,765 $ 956 $ 430 $ 3,633 $ 392,561 Unproved development costs 46,268 — 4,170 — — 50,438 Total unevaluated costs $ 396,045 $ 37,765 $ 5,126 $ 430 $ 3,633 $ 442,999 There were no individually significant properties or significant development projects included in the Company’s unproved property balance. The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established. The majority of these costs are expected to be evaluated and included in the depletion base within three years . |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures The Company seeks to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. The objective of these acquisitions is to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons. The Company acquired certain oil and natural gas and other assets that affect the comparability of its financial condition and results of operation between the year ended December 31, 2016 and 2015 , as described below. October 2016 Acquisition During October 2016, the Company completed two acquisitions of certain assets for a total purchase price of $9.6 million composed of cash, forgiven receivables, and transferred liabilities. The acquired properties were comprised primarily of additional oil and gas leasehold interests in properties operated by the Company. August 2016 Acquisition During August 2016, the Company completed two acquisitions of certain assets for a total purchase price of $3.9 million composed of cash and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests. June 2016 Acquisition In May 2016, we entered into a purchase and sale agreement (the "GC Agreement") with a large publicly-traded company pursuant to which we agreed to acquire a total of approximately 72,000 gross ( 33,100 net) acres in an area referred to as the Greeley-Crescent development area in the Wattenberg Field for $505 million (the "GC Acquisition"). Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the GC Agreement. In June 2016, the Company closed on the portion of the assets comprised of the undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. A second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired, and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all. The first closing on June 14, 2016 was for a total purchase price of $486.4 million , net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement. The first closing was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million r elated to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 14, 2016 Consideration given: Cash $ 485,141 Net liabilities assumed, including asset retirement obligations 1,273 Total consideration given $ 486,414 Allocation of Purchase Price Proved oil and gas properties (1) $ 132,903 Unproved oil and gas properties 353,511 Total fair value of assets acquired $ 486,414 (1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rat e of 11.5% , a nd assumptions regarding the timing and amount of future development and operating costs. For th e year ended December 31, 2016, the results of operations of the acquired assets, representing approximately $5.3 million of revenue and $4.4 million of operating income, have been included in the Company's consolidated statements of operations. The following table presents the unaudited pro forma combined results of operations for the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015 as if the first closing had occurred on September 1, 2014. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Oil and natural gas revenues $ 110,635 $ 37,403 $ 147,643 Net loss $ (218,578 ) $ (122,577 ) $ 21,507 Net loss per common share Basic $ (1.10 ) $ (0.67 ) $ 0.13 Diluted $ (1.10 ) $ (0.67 ) $ 0.13 February 2016 Acquisition In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million . The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties. This allocation reflects significant use of estimates. October 2015 Acquisition In October 2015, the Company closed the acquisition of certain assets ("KPK Acquisition") from a private company for a total purchase price of $85.2 million , net of customary closing adjustments. The purchase price was composed of $35.0 million in cash and $49.8 million in restricted common stock of the Company plus the assumption of certain liabilities. The KPK Acquisition encompassed approximately 4,300 net acres of oil and gas leasehold interests and related assets and net production of approximately 1,200 BOED at the time of purchase. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations , which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 20, 2015. Transaction costs related to the acquisition were expensed as incurred. The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 20, 2015 Consideration given: Cash $ 35,045 Synergy Resources Corp. common stock (1) 49,840 Net liabilities assumed, including asset retirement obligations 284 Total consideration given $ 85,169 Allocation of Purchase Price Proved oil and gas properties (2) $ 46,333 Unproved oil and gas properties 37,766 Other assets, including accounts receivable 1,070 Total fair value of assets acquired $ 85,169 (1) The fair value of the consideration attributed to the common stock under ASC 805 was based on the Company's closing stock price on the measurement date of October 20, 2015 ( 4,418,413 shares at $11.28 per share). (2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 12% , and assumptions regarding the timing and amount of future development and operating costs. For the twelve months ended December 31, 2016 and the four months ended December 31, 2015, the results of operations of the acquired assets, representing approximately $5.1 million and $1.1 million of revenue and $4.5 million and $0.8 million of operating income, respectively, have been included in the Company's consolidated statements of operations. The following table presents the unaudited pro forma combined results of operations for the four months ended December 31, 2015 and the year ended August 31, 2015 as if the transaction had occurred on September 1, 2014. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Four Months Ended December 31, 2015 Year Ended August 31, 2015 Oil and natural gas revenues $ 35,389 $ 138,145 Net loss $ (122,529 ) $ 21,592 Net loss per common share Basic $ (1.12 ) $ 0.22 Diluted $ (1.12 ) $ 0.22 Divestitures In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyer of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool. |
Depletion, depreciation and acc
Depletion, depreciation and accretion | 12 Months Ended |
Dec. 31, 2016 | |
Other Costs and Disclosures [Abstract] | |
Depletion, depreciation and accretion | Depletion, depreciation, and accretion Depletion, depreciation, and accretion consisted of the following (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Depletion of oil and gas properties $ 45,193 $ 18,371 $ 65,158 $ 32,132 Depreciation and accretion 1,485 405 711 826 Total DD&A Expense $ 46,678 $ 18,776 $ 65,869 $ 32,958 Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the year ended December 31, 2016 , production of 4,271 MBOE represented 4.4% of estimated total proved reverses. For the four months ended December 31, 2015, production of 1,320 MBOE represented 2.0% of estimated total proved reserves. For the year ended August 31, 2015, production of 3,194 MBOE represented 5.3% of estimated total proved reserves. For the year ended August 31, 2014, production of 1,566 MBOE represented 4.6% of estimated total proved reserves. DD&A expense was $10.93 per BOE and $14.22 per BOE for the year ended December 31, 2016 and the four months ended December 31, 2015, respectively. DD&A expense was $20.62 per BOE and $21.05 per BOE for the years ended August 31, 2015 and 2014, respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Years Ended August 31, 2015 Beginning asset retirement obligation $ 13,400 $ 12,334 $ 4,730 Obligations incurred with development activities 773 1,590 1,372 Obligations assumed with acquisitions 2,230 229 1,913 Accretion expense 1,046 348 553 Obligations discharged with asset retirements and settlements (4,739 ) (1,101 ) — Revisions in previous estimates 3,748 — 3,766 Ending asset retirement obligation $ 16,458 $ 13,400 $ 12,334 During the year ended December 31, 2016 , the Company increased its asset retirement obligation by $3.7 million due to a revision to the expected timing of the future cash flows. During the year ended August 31, 2015, the Company increased its asset retirement obligation by $3.8 million due to a revision to its assumption of the average cost to plug and abandon each well. |
Revolving Credit Facility
Revolving Credit Facility | 12 Months Ended |
Dec. 31, 2016 | |
Line of Credit Facility [Abstract] | |
Revolving Credit Facility | Revolving Credit Facility The Company maintains a revolving credit facility with a bank syndicate with a maturity date of December 15, 2019 . The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of December 31, 2016 , the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $160 million . As of December 31, 2016 , there was no outstanding principal balance as compared to a principal balance of $78 million as of December 31, 2015 . The Company has an outstanding letter of credit of approximately $0.5 million . In October 2016, the Revolver was increased from $145 million to $160 million in connection with the semi-annual redetermination of the borrowing base. The next semi-annual redetermination is scheduled for May 2017 . Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the year ended December 31, 2016 , the four months ended December 31, 2015 , and the year ended August 31, 2015 was 2.63% , 2.5% , and 2.5% , respectively. Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects, an unscheduled redetermination could be prepared. The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report. Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day o f any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2016 , the most recent compliance date, the C ompany was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period. |
Notes Payable
Notes Payable | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Notes Payable | Notes Payable In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 10.5% . The net proceeds were used to fund the GC Acquisition as discussed further in Note 3 . At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes ( 104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications. As of December 31, 2016 , the most recent compliance date, the C ompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period. |
Commodity Derivative Instrument
Commodity Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivative Instruments | Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volume s and commodities covered and the relevant strike prices , is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver. A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. Conversely, a "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where, at settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price. Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties and an exchange. Two of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. The Company’s commodity derivative contracts as of December 31, 2016 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per month) Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 60.00 Jan 1, 2017 - Dec 31, 2017 Collar 20,000 $ 45.00 70.00 Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 $ 65.00 Jan 1, 2017 - Apr 30, 2017 Put 20,000 $ 50.00 $ — May 1, 2017 - Aug 31, 2017 Put 20,000 $ 55.00 $ — Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 $ 65.00 Jan 1, 2017 - Dec 31, 2017 Collar 15,208 $ 45.00 $ 65.00 Jan 1, 2017 - Dec 31, 2017 Collar 15,208 $ 45.00 $ 65.10 Settlement Period Derivative Average Volumes Floor Ceiling Natural Gas - NYMEX Henry Hub Jan 1, 2017 - Dec 31, 2017 Collar 100,000 $ 2.75 $ 4.00 Jan 1, 2017 - Dec 31, 2017 Collar 152,083 $ 2.75 $ 3.90 Sep 1, 2017 - Dec 31, 2017 Collar 91,500 $ 2.75 $ 4.10 Sep 1, 2017 - Dec 31, 2017 Collar 15,250 $ 3.00 $ 4.31 Feb 1, 2017 - Dec 31, 2017 Collar 109,309 $ 3.00 $ 4.30 Natural Gas - CIG Rocky Mountain Jan 1, 2017 - Apr 30, 2017 Collar 100,000 $ 2.80 $ 3.95 May 1, 2017 - Aug 31, 2017 Collar 110,000 $ 2.50 $ 3.06 Jan 1, 2017 - Dec 31, 2017 Collar 200,000 $ 2.50 $ 3.27 Jan 1, 2017 - Dec 31, 2017 Collar 100,000 $ 2.60 $ 3.20 Offsetting of Derivative Assets and Liabilities As of December 31, 2016 and 2015 , all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying consolidated balance sheets. The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands): As of December 31, 2016 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity Derivative contracts Current assets $ 2,045 $ (1,748 ) $ 297 Commodity Derivative contracts Noncurrent assets $ — $ — $ — Commodity Derivative contracts Current liabilities $ 4,622 $ (1,748 ) $ 2,874 Commodity Derivative contracts Noncurrent liabilities $ — $ — $ — As of December 31, 2015 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity Derivative contracts Current assets $ 6,719 $ (147 ) $ 6,572 Commodity Derivative contracts Noncurrent assets $ 3,354 $ (358 ) $ 2,996 Commodity Derivative contracts Current liabilities $ 147 $ (147 ) $ — Commodity Derivative contracts Noncurrent liabilities $ 358 $ (358 ) $ — The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Realized gain (loss) on commodity derivatives $ 2,355 $ 1,577 $ 30,466 $ (2,138 ) Unrealized gain (loss) on commodity derivatives (10,105 ) 4,905 1,790 2,459 Total gain (loss) $ (7,750 ) $ 6,482 $ 32,256 $ 321 Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date, the proceeds from or cost of early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015, the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million . The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Monthly settlement 4,396 2,331 $ 11,212 $ (2,138 ) Previously incurred premiums attributable to settled commodity contracts (2,041 ) (754 ) (1,255 ) — Early liquidation — — 20,509 — Total realized gain (loss) $ 2,355 $ 1,577 $ 30,466 $ (2,138 ) Credit Related Contingent Features As of December 31, 2016 , two of the five counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third and fourth counterparties, which are not lenders under the credit facility, are unsecured and do not require the posting of collateral. The agreement with the fifth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC 820, Fair Value Measurements and Disclosure , establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: • Level 1: Quoted prices available in active markets for identical assets or liabilities; • Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and • Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models. The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 2 , 3 , and 5 for further discussion of unproved properties, business combinations, and asset retirement obligations, respectively. The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 for additional information. The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the proved properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using the same inputs as described in the paragraph above. For the asset retirement obligation assumed, the fair value is determined using the same inputs as described in the paragraph below. See Note 3 for additional information. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note 5 for additional information. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 297 $ — $ 297 Commodity derivative liability $ — $ 2,874 $ — $ 2,874 Fair Value Measurements at December 31, 2015 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 9,568 $ — $ 9,568 Commodity derivative liability $ — $ — $ — $ — Commodity Derivative Instruments The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2016, derivative instruments utilized by the Company consist of puts and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are primarily traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2. Fair Value of Financial Instruments The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value. The fair value of the notes payable is estimated to be $86.3 million at December 31, 2016. The Company determined the fair value of its notes payable at December 31, 2016 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2. |
Interest Expense
Interest Expense | 12 Months Ended |
Dec. 31, 2016 | |
Interest and Debt Expense [Abstract] | |
Interest Expense | Interest Expense The components of interest expense are (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Revolving credit facility $ 154 $ 661 $ 2,776 $ 986 Note payable 3,940 — — — Amortization of debt issuance costs 1,638 431 853 448 Less: interest capitalized (5,732 ) (1,092 ) (3,384 ) (1,434 ) Interest expense, net $ — $ — $ 245 $ — |
Shareholders' Equity
Shareholders' Equity | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |
Shareholders' Equity | Shareholders’ Equity The Company's classes of stock are summarized as follows: As of December 31, 2016 2015 Preferred stock, shares authorized 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil Common stock, shares authorized 300,000,000 300,000,000 Common stock, par value $ 0.001 $ 0.001 Common stock, shares issued and outstanding 200,647,572 110,033,601 Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares. As of December 31, 2016, the shareholders had approved the number of common shares authorized for issuance of 300,000,000 . Shares of the Company’s common stock were issued during the year ended December 31, 2016 , the four months ended December 31, 2015 and each of the years ended August 31, 2015, and 2014, as described further below. Sales of common stock During the year ended December 31, 2016, the four months ended December 31, 2015, and the years ended August 31, 2015 and 2014, the Company sold shares of its common stock in public offerings as follows: • In May and June 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. • In April 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. • In January 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. • In February 2015, the Company completed the sale of common stock in an underwritten public offering led by Seaport Global Securities LLC. A summary of the transactions is shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering. Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of common shares sold 90,275,000 — 18,613,952 — Offering price per common share $ 6.02 $ — $ 10.75 $ — Net proceeds (in thousands) $ 543,400 $ — $ 190,845 $ — In January 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 14,000,000 shares of its common stock to the Underwriters at a price of $5.545 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,100,000 shares of common stock on the same terms and conditions. The option was exercised on January 26, 2016, bringing the total number of shares issued to 16,100,000 . Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.2 million . Proceeds from the offering were used for general corporate purposes, including the continued development of our acreage position in the Wattenberg Field and repayment of amounts borrowed under the Revolver. In April 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 19,500,000 shares of its common stock to the Underwriters at a price of $7.3535 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,925,000 shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to 22,425,000 . Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million . Proceeds from the offering were used for general corporate purposes, including the continued development of our acreage position in the Wattenberg Field and funding a portion of the purchase price of the GC Acquisition described in Note 3 . In May 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell 45,000,000 shares of its common stock to the Underwriters at a price of $5.597 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 6,750,000 shares of common stock on the same terms and conditions. The option was exercised on June 6, 2016, bringing the total number of shares issued to 51,750,000 . Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million . The Company used the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note 3 . Common stock issued for acquisition of mineral property interests During the periods presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction. Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of common shares issued for mineral property leases — 37,051 995,672 357,901 Number of common shares issued for acquisitions — 4,418,413 4,648,136 872,483 Total common shares issued — 4,455,464 5,643,808 1,230,384 Average price per common share $ — $ 11.28 $ 10.67 $ 9.09 Aggregate value of shares issues (in thousands) $ — $ 50,265 $ 60,221 $ 11,184 Common stock warrants The Company previously issued warrants to purchase common stock. There were no warrants outstanding as of August 31, 2015, December 31, 2015 and December 31, 2016 . The following reflects the activity since September 1, 2013: Series C – During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering. Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants. Each Series C warrant entitled the holder to purchase one share of common stock for $6.00 and expired on December 31, 2014, if not previously exercised. During the years ended August 31, 2015, 2014, and 2013, the following Series C warrants were exercised: 2,561,415 , 5,938,585 , and 500,000 , respectively. Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C unit offering. Each Series D warrant entitled the holder to purchase one share of common stock for $1.60 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The Series D warrants expired, if not previously exercised, on December 31, 2014. During the years ended August 31, 2015, 2014, and 2013, the following warrants were exercised: 1,058 , 140,744 , and 627,799 , respectively. Investor Relations Warrants – During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services (the "Investor Relations Warrants"). Each Investor Relations Warrant entitled the holder to purchase one share of common stock for $2.69 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The warrants became exercisable in equal quarterly installments over a one -year period. During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement with the firm. During the years ended August 31, 2015, 2014, and 2013, the following Investor Relations Warrants were exercised: nil , 25,000 , and 25,000 , respectively. The following table summarizes activity for common stock warrants for the periods presented: Number of Shares Issuable Upon Warrant Exercise Weighted-Average Exercise Price Per Share Outstanding, August 31, 2014 2,562,473 $ 6.00 Exercised (2,562,473 ) $ 6.00 Forfeited / Expired — $ — Outstanding, August 31, 2015 — $ — Exercised — $ — Forfeited / Expired — $ — Outstanding, December 31, 2015 — $ — Exercised — $ — Forfeited / Expired — $ — Outstanding, December 31, 2016 — $ — |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share Basic earnings per share includes no dilution and is computed by dividing net income (loss) by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, non-vested performance-vested stock units, non-vested restricted stock units, stock bonus shares, and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share. The following table sets forth the share calculation of diluted earnings per share: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Weighted-average shares outstanding - basic 173,774,035 107,789,554 94,628,665 76,214,737 Potentially dilutive common shares from: Stock options — — 672,493 479,222 Restricted stock units and stock bonus shares — — 18,111 — Performance-vested stock units — — — — Warrants — — — 1,114,095 Weighted-average shares outstanding - diluted 173,774,035 107,789,554 95,319,269 77,808,054 The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above as such securities had an anti-dilutive effect on earnings per share: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Potentially dilutive common shares from: Stock options 6,001,500 5,056,000 2,785,500 533,000 Restricted stock units and stock bonus shares 890,336 915,867 145,000 — Performance-vested stock units 1 478,510 — — — Warrants — — — — Total 7,370,346 5,971,867 2,930,500 533,000 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation In addition to cash compensation, the Company may compensate employees and directors with equity based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. The amount of stock-based compensation was as follows (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Stock options $ 5,417 $ 2,161 $ 4,741 $ 1,767 Performance stock units 1,047 — — — Restricted stock units and stock bonus shares 4,232 7,162 2,950 1,201 Total stock-based compensation 10,696 9,323 7,691 2,968 Less: stock-based compensation capitalized (1,205 ) (892 ) (778 ) (514 ) Total stock-based compensation expense $ 9,491 $ 8,431 $ 6,913 $ 2,454 General Description of Stock Award Plans In December 2015, the Company's shareholders approved the 2015 Equity Incentive Plan (the "2015 Plan"). The 2015 Plan replaced three equity compensation plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan (the "2011 Plans"). No additional options or stock bonus shares will be issued under the 2011 Plans. The 2015 Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in the Company’s common stock or units of the Company’s common stock as well as cash bonus awards. Employees, directors, officers, consultants, and advisors are eligible to receive such awards, provided that bona fide services are rendered by such consultants or advisors (other than services in connection with the offering or sale of securities or as a market maker or promoter of securities of the Company). As of December 31, 2016 , there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 2,149,238 shares were remaining for future issuance. Stock options During the respective periods, the Company granted the following stock options: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of options to purchase common shares 1,067,500 1,142,500 2,377,500 433,000 Weighted-average exercise price $ 7.19 $ 10.84 $ 11.55 $ 10.37 Term (in years) 10 years 10 years 10 years 10 years Vesting Period (in years) 3 - 5 years 3.7-5 years 3-5 years 5 years Fair Value (in thousands) $ 3,860 $ 6,591 $ 13,266 $ 3,009 The assumptions used in valuing stock options granted during each of the periods presented were as follows: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Expected term 6.4 years 6.5 years 6.5 years 6.7 years Expected volatility 55 % 53 % 47 % 73 % Risk free rate 1.25 - 2.00% 1.8 - 2.0% 1.4 - 2.0% 1.8 - 2.3% Expected dividend yield — % — % — % — % The following table summarizes activity for stock options for the periods presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2013 1,820,000 $ 4.88 8.7 years $ 8,160 Granted 433,000 10.37 Exercised (61,000 ) 3.71 481 Expired (25,000 ) 10.32 Outstanding, August 31, 2014 2,167,000 5.94 8.0 years 16,287 Granted 2,377,500 11.55 Exercised (258,000 ) 3.81 2,103 Forfeited (110,000 ) 4.97 Outstanding, August 31, 2015 4,176,500 9.29 8.6 years 8,187 Granted 1,142,500 10.84 Exercised (188,000 ) 6.56 981 Expired (60,000 ) 11.74 Forfeited (15,000 ) 11.68 Outstanding, December 31, 2015 5,056,000 9.71 8.7 years 4,351 Granted 1,067,500 7.19 Exercised (20,000 ) 3.91 117 Expired — — Forfeited (102,000 ) 10.40 Outstanding, December 31, 2016 6,001,500 $ 9.27 8.0 years $ 6,515 Outstanding, Exercisable at December 31, 2016 2,406,100 $ 8.42 7.0 years $ 4,297 Outstanding, Vested and Expected to Vest at December 31, 2016 5,937,601 $ 9.24 7.9 years $ 6,511 The following table summarizes information about issued and outstanding stock options as of December 31, 2016 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Remaining Contractual Life Weighted-Average Exercise Price per Share Options Weighted-Average Exercise Price per Share Under $5.00 630,000 4.7 years $ 3.50 589,000 $ 3.48 $5.00 - $6.99 1,012,000 7.9 years 6.38 430,000 6.51 $7.00 - $10.99 1,617,500 8.5 years 9.34 383,900 9.72 $11.00 - $13.46 2,742,000 8.4 years 11.61 1,003,200 11.63 Total 6,001,500 8.0 years $ 9.27 2,406,100 $ 8.42 The estimated unrecognized compensation cost from stock options not vested as of December 31, 2016 , which will be recognized ratably over the remaining vesting phase, is as follows: Unrecognized compensation, net of estimated forfeitures (in thousands) $ 15,330 Remaining vesting phase 3.2 years Restricted stock units and stock bonus awards The Company grants shares of restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years . Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award. The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented: Number of Weighted-Average Not vested, August 31, 2013 46,667 $ 6.75 Granted 343,780 11.34 Vested (97,114 ) 11.38 Forfeited — — Not vested, August 31, 2014 293,333 10.60 Granted 547,699 11.17 Vested (208,532 ) 11.09 Forfeited — — Not vested, August 31, 2015 632,500 10.93 Granted 919,604 10.08 Vested (636,237 ) 10.13 Forfeited — — Not vested, December 31, 2015 915,867 10.63 Granted 464,533 7.66 Vested (424,483 ) 9.92 Forfeited (65,581 ) 8.99 Not vested, December 31, 2016 890,336 $ 9.55 The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2016 , which will be recognized ratably over the remaining vesting phase, is as follows: Unrecognized compensation, net of estimated forfeitures (in thousands) $ 6,711 Remaining vesting phase 2.8 years Performance-vested stock units In March 2016, the Company granted performance-vested stock units ("PSUs") to certain executives under its long term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three -year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three -year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards. The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company’s peers. The assumptions used in valuing the PSUs granted were as follows: Year Ended December 31, 2016 Weighted-average expected term 2.7 years Weighted-average expected volatility 58 % Weighted-average risk free rate 0.87 % During the year ended December 31, 2016 , the Company granted 490,713 PSUs to certain executives. The fair value of the PSUs granted during the year ended December 31, 2016 was $4.0 million . As of December 31, 2016 , unrecognized compensation expense for PSUs was $2.8 million and will be amortized through 2018. A summary of the status and activity of PSUs is presented in the following table: Number of Units 1 Weighted-Average Grant-Date Fair Value Not vested, December 31, 2015 — $ — Granted 490,713 8.10 Vested — — Forfeited (12,203 ) 8.22 Not vested, December 31, 2016 478,510 $ 8.09 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the vesting condition. |
Defined Contribution Plan
Defined Contribution Plan | 12 Months Ended |
Dec. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Defined Contribution Plan | Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 3% of eligible compensation plus 50% of compensation deferrals in excess of 3% of eligible compensation not to exceed more than 5% of eligible compensation. The Company contributed approximately $0.4 million for year ended December 31, 2016 , $0.1 million for the four months ended December 31, 2015, and $0.1 million during the years ended August 31, 2015 and 2014 to the plan. Effective January 1, 2017, the Company modified its 401(k) plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The income tax provision is comprised of the following (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Current: Federal $ 106 $ — $ (4 ) $ 4 State — — (111 ) 111 Total current income tax expense (benefit) $ 106 $ — $ (115 ) $ 115 Deferred: Federal $ (74,099 ) $ (45,332 ) $ 10,820 $ 13,748 State (6,651 ) (4,074 ) 972 1,151 Total deferred income tax (benefit) expense $ (80,750 ) $ (49,406 ) $ 11,792 $ 14,899 Valuation allowance 80,750 39,399 — — Income tax expense (benefit) $ 106 $ (10,007 ) $ 11,677 $ 15,014 A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Federal income tax at statutory rate $ (74,489 ) $ (45,200 ) $ 10,105 $ 14,915 State income taxes, net of federal tax (6,685 ) (4,062 ) 908 1,341 Statutory depletion (287 ) (150 ) (451 ) (1,266 ) Stock-based compensation 383 — 92 — Non-deductible compensation — — 850 125 Valuation allowance 80,750 39,399 — — Other 434 6 173 (101 ) Income tax provision $ 106 $ (10,007 ) $ 11,677 $ 15,014 Effective rate expressed as a percentage — % 8 % 39 % 34 % In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands): As of December 31, 2016 2015 Deferred tax assets (liabilities): Net operating loss carryforward $ 47,462 $ 11,855 Stock-based compensation 5,576 3,304 Basis of oil and gas properties 62,707 23,656 Statutory depletion 4,028 2,802 Unrealized (gain) loss on commodity derivative 1,334 (2,410 ) Other (958 ) 192 120,149 39,399 Valuation allowance on tax assets (120,149 ) (39,399 ) Deferred tax asset (liability), net $ — $ — At December 31, 2016 , the Company has a net operating loss carryforward for federal and state tax purposes of approximately $140.3 million that could be utilized to offset taxable income of future years. For financial reporting purposes, the Company has net operating losses of approximately $128.1 million for federal and state. The difference of $12.2 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. Substantially all of the carryforward will commence expiring in 2031 , 2032, and 2033 . At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the year ended December 31, 2016 , the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses. The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards. As of December 31, 2016 , the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2012 are still subject to examination by tax authorities. |
Other Commitments and Contingen
Other Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Volume Commitments During 2014, the Company entered into oil transportation agreements with three counterparties. Deliveries under two of the transportation agreements commenced during the four months ended December 31, 2015. Deliveries under the third transportation agreement commenced during the year ended December 31, 2016. In collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both currently expected to be completed by late 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. This contractual obligation can be reduced by our proportionate share of the collective volumes delivered to the plant by other producers in the D-J Basin that are in excess of the total commitment. Pursuant to these agreements, we must deliver specific amounts of oil and natural gas either from our own production or from oil and natural gas that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described in the preceding paragraph, are as follows: Year ending December 31, Oil (MBbls) 2017 3,944 2018 4,255 2019 4,255 2020 3,700 2021 1,672 Thereafter — Total 17,826 During the year ended December 31, 2016 and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.6 million and $2.8 million , respectively, as we were unable to meet all of the obligations during the period. No such charges were incurred during the years ended August 31, 2015 and 2014. Office leases In September 2016, the Company entered into a new sixty-five-month lease for the Company’s principal office space located in Denver, which is expected to commence in the first quarter of 2017. At the Company's current location, lease expense is approximately $50,000 per month which will continue until the new space is ready to be occupied. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. A schedule of the minimum lease payments under non-cancelable operating leases as of December 31, 2016 follows (in thousands): 2017 398 2018 840 2019 859 2020 878 2021 875 Thereafter 477 Total 4,327 Rent expense for offices leases was $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million and $0.2 million for the years ended August 31, 2015 and 2014, respectively. Litigation From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows. On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering oil and gas properties in Weld County, Colorado. In June 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims including claims for trespass. The Company and Defendants entered into a settlement agreement on December 6, 2016, resolving all claims and counterclaims related to the litigation. The terms of the settlement agreement did not have a material effect on the Company. In July 2016, the Company was informed by the CDPHE that it expects to expand its inspection of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. A subsequent February 2017 tolling agreement between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. We are working with the CDPHE to respond to any continuing concerns. We cannot predict the outcome of this matter, but we expect that any potential resolution of these claims would be on a field-wide basis. |
Supplemental Schedule of Inform
Supplemental Schedule of Information to the Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Schedule of Information to the Statements of Cash Flows | Supplemental Schedule of Information to the Consolidated Statements of Cash Flows The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Supplemental cash flow information: Interest paid $ 3,779 $ 683 $ 2,817 $ 989 Income taxes paid (refunded) $ 106 $ (150 ) $ 202 $ — Non-cash investing and financing activities: Accrued well costs payable $ 42,779 $ 31,414 $ 33,071 $ 71,849 Assets acquired in exchange for common stock $ — $ 50,265 $ 60,221 $ 11,184 Obligations incurred with development activities $ 773 $ 1,819 $ 7,051 $ 1,610 Obligations assumed with acquisitions $ 2,230 $ — $ — $ — Obligations discharged with asset retirements and divestitures $ (4,739 ) $ — $ — $ — |
Unaudited Oil and Gas Reserves
Unaudited Oil and Gas Reserves Information | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Unaudited Oil and Gas Reserves Information | Unaudited Oil and Natural Gas Reserves Information Oil and Natural Gas Reserve Information: Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott. Reserve information for the properties was prepared in accordance with guidelines established by the SEC. The reserve estimates prepared as of each of the period ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC. The guidance included updated definitions of proved developed and proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms. Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the twelve-month period before the respective determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking. The guidance broadened the types of technologies that may be used to establish reserve estimates. The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented: Oil (MBbl) Natural Gas (MMcf) MBOE Balance, August 31, 2013 7,047 40,690 13,829 Revision of previous estimates 83 3,047 591 Purchase of reserves in place 1,028 5,956 2,021 Extensions, discoveries, and other additions 9,142 49,289 17,357 Sale of reserves in place (35 ) (56 ) (44 ) Production (941 ) (3,747 ) (1,566 ) Balance, August 31, 2014 16,324 95,179 32,188 Revision of previous estimates (1,699 ) (4,889 ) (2,513 ) Purchase of reserves in place 4,201 21,957 7,860 Extensions, discoveries, and other additions 11,465 73,392 23,696 Sale of reserves in place (629 ) (4,337 ) (1,352 ) Production (1,970 ) (7,344 ) (3,194 ) Balance, August 31, 2015 27,692 173,958 56,685 Revision of previous estimates (10,917 ) (38,931 ) (17,407 ) Purchase of reserves in place 4,380 58,959 14,207 Extensions, discoveries, and other additions 8,263 62,301 18,647 Sale of reserves in place (2,297 ) (14,149 ) (4,655 ) Production (742 ) (3,468 ) (1,320 ) Balance, December 31, 2015 26,379 238,670 66,157 Revision of previous estimates (7,788 ) (80,549 ) (21,213 ) Purchase of reserves in place 23,141 197,103 55,991 Extensions, discoveries, and other additions 1,457 13,018 3,627 Sale of reserves in place (2,900 ) (24,235 ) (6,939 ) Production (2,257 ) (12,086 ) (4,271 ) Balance, December 31, 2016 38,032 331,921 93,352 Proved developed and undeveloped reserves: Developed at August 31, 2014 6,616 38,162 12,977 Undeveloped at August 31, 2014 9,708 57,017 19,211 Balance, August 31, 2014 16,324 95,179 32,188 Developed at August 31, 2015 7,393 46,026 15,064 Undeveloped at August 31, 2015 20,299 127,932 41,621 Balance, August 31, 2015 27,692 173,958 56,685 Developed at December 31, 2015 8,410 56,751 17,868 Undeveloped at December 31, 2015 17,969 181,919 48,289 Balance, December 31, 2015 26,379 238,670 66,157 Developed at December 31, 2016 7,435 62,570 17,863 Undeveloped at December 31, 2016 30,597 269,351 75,489 Balance, December 31, 2016 38,032 331,921 93,352 Notable changes in proved reserves for the year ended December 31, 2016 included: • Purchases of reserves in place. For the year ended December 31, 2016 , purchases of reserves in place of 55,991 MBOE were primarily attributable to the acquisition of proved reserves in the GC Acquisition. Please see Note 3 for further information. • Revision of previous estimates. For the year ended December 31, 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 21,213 MBOE primarily as a result of the removal of certain legacy PUD locations as they are now expected to be developed beyond the three-year drilling plan. • Extensions and discoveries. For the year ended December 31, 2016 , total extensions and discoveries of 3,627 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 6 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the four months ended December 31, 2015 included: • Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBO E were attributable to the acquisition of proved reserves. Please see Note 3 for further information. • Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan removed undeveloped reserves that are not projected to be drilled in the next three years and reflected the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells; in addition, we high-graded our inventory of wells to be drilled. • Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 9 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the year ended August 31, 2015 included: • Purchases of reserves in place. For the year ended August 31, 2015, purchases of reserves in place of 7,860 MBOE were attributable to the acquisition of proved reserves. • Revision of previous estimates. For the year ended August 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan. • Extensions and discoveries. For the year ended August 31, 2015, total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the year ended August 31, 2014 included: • Purchases of reserves in place. For the year ended August 31, 2014, purchases of reserves in place of 2,021 MBOE were attributable to the acquisition of producing oil and natural gas wells and undeveloped acreage. • Revision of previous estimates. For the year ended August 31, 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591 MBOE. • Extensions and discoveries. For the year ended August 31, 2014, total extensions and discoveries of 17,357 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves. Standardized Measure of Discounted Future Net Cash Flows: The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves. Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs. The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs. Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves. Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation. The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands): As of December 31, As of August 31, 2016 2015 2015 2014 Future cash inflow $ 2,180,673 $ 1,710,610 $ 2,046,615 $ 1,839,987 Future production costs (644,093 ) (462,097 ) (653,009 ) (395,019 ) Future development costs (584,537 ) (340,449 ) (510,720 ) (412,517 ) Future income tax expense (90,195 ) (108,172 ) (144,399 ) (252,925 ) Future net cash flows 861,848 799,892 738,487 779,526 10% annual discount for estimated timing of cash flows (427,587 ) (408,939 ) (372,658 ) (376,827 ) Standardized measure of discounted future net cash flows $ 434,261 $ 390,953 $ 365,829 $ 402,699 There have been significant fluctuations in the posted prices of oil and natural gas during the last three years. Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices. The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials: Oil (Bbl) Natural Gas (Mcf) December 31, 2016 (Average) $ 36.07 $ 2.44 December 31, 2015 (Average) $ 41.33 $ 2.60 August 31, 2015 (Average) $ 53.27 $ 3.28 August 31, 2014 (Average) $ 89.48 $ 5.03 The prices for the December 31, 2016 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2016 through December 31, 2016 . The December 31, 2016 oil price of $36.07 per barrel (West Texas Intermediate Cushing) was $5.26 lower than the December 31, 2015 oil price of $41.33 per barrel. The December 31, 2016 natural gas price of $2.44 per Mcf (Henry Hub) was $0.16 lower than the December 31, 2015 price of $2.60 per Mcf. Changes in the Standardized Measure of Discounted Future Net Cash Flows: The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Standardized measure, beginning of period $ 390,953 $ 365,829 $ 402,699 $ 181,732 Sale and transfers, net of production costs (81,468 ) (25,222 ) (98,486 ) (86,808 ) Net changes in prices and production costs (64,387 ) (81,968 ) (233,051 ) 15,828 Extensions, discoveries, and improved recovery 18,795 116,343 173,918 300,087 Changes in estimated future development costs (6,016 ) (7,195 ) 10,002 (20,817 ) Previously estimated development costs incurred during the period 62,502 5,923 4,957 15,000 Revision of quantity estimates (110,306 ) (36,820 ) (38,340 ) 4,589 Accretion of discount 44,703 14,610 57,629 23,612 Net change in income taxes 5,104 25,263 58,547 (76,616 ) Divestitures of reserves (26,839 ) (43,754 ) (19,234 ) (925 ) Purchase of reserves in place 228,855 77,024 56,795 47,017 Changes in timing and other (27,635 ) (19,080 ) (9,607 ) — Standardized measure, end of period $ 434,261 $ 390,953 $ 365,829 $ 402,699 |
Unaudited Quarterly Financial D
Unaudited Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Unaudited Quarterly Financial Data | Unaudited Financial Data The Company’s unaudited quarterly financial information is as follows (in thousands, except share data): Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 18,273 $ 23,947 $ 26,234 $ 38,695 Expenses 71,356 172,157 45,887 29,324 Operating income (loss) (53,083 ) (148,210 ) (19,653 ) 9,371 Other income (expense) 1,682 (5,537 ) 417 (4,070 ) Income (loss) before income taxes (51,401 ) (153,747 ) (19,236 ) 5,301 Income tax provision (benefit) — 101 5 — Net income (loss) $ (51,401 ) $ (153,848 ) $ (19,241 ) $ 5,301 Net income (loss) per common share: (1) Basic $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Diluted (2) $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Weighted-average shares outstanding: Basic 121,392,736 172,013,551 200,515,555 200,585,800 Diluted 121,392,736 172,013,551 200,515,555 201,254,678 Year Ended December 31, 2015 First Quarter (3) Second Quarter (3) Third Quarter (3) Fourth Quarter (3) Revenues $ 18,938 $ 28,286 $ 33,378 $ 25,448 Expenses 24,086 31,303 128,366 79,018 Operating income (5,148 ) (3,017 ) (94,988 ) (53,570 ) Other income (expense) 3,446 (4,474 ) 6,547 5,383 Income before income taxes (1,702 ) (7,491 ) (88,441 ) (48,187 ) Income tax provision (709 ) (2,903 ) (10,520 ) — Net income $ (993 ) $ (4,588 ) $ (77,921 ) $ (48,187 ) Net income per common share: (1) Basic $ (0.01 ) $ (0.04 ) $ (0.74 ) $ (0.44 ) Diluted (2) $ (0.01 ) $ (0.04 ) $ (0.74 ) $ (0.44 ) Weighted-average shares outstanding: Basic 97,241,301 104,562,662 105,100,849 108,664,875 Diluted 97,241,301 104,562,662 105,100,849 108,664,875 The Company’s unaudited financial information for the four months ended December 31, 2014 is as follows (in thousands, except share data): Four Months Ended December 31, 2014 Revenues $ 52,931 Expenses 38,047 Operating income 14,884 Other income (expense) 27,717 Income before income taxes 42,601 Income tax provision 15,802 Net income $ 26,799 Net income per common share: Basic $ 0.34 Diluted (2) $ 0.33 Weighted-average shares outstanding: Basic 79,971,698 Diluted 80,693,410 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. 3 The Company has recast this quarterly financial information for the year ended December 31, 2015 to reflect the change in the Company's fiscal year. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events In January 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of acreage outside of the Company's core development area. The transaction resulted in the Company divesting approximately 10,000 net undeveloped acres and approximately 700 BOED of associated production for $71 million . The transaction is expected to close in the first quarter of 2017. In January 2017, we executed a purchase and sale agreement with a private party for the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $25 million . The transaction is expected to close in the first quarter of 2017. |
Organization and Summary of S27
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiary. All significant intercompany balances and transactions have been eliminated in consolidation. The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). |
Change of Year-End | Change of Year-End: On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year. |
Use of Estimates | Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. |
Oil and Gas Properties | Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the year ended December 31, 2016 , the Company recognized ceiling test impairments totaling $215.2 million . The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. |
Oil and Natural Gas Reserves | Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves. |
Capitalized Interest | Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 10 for additional information. |
Capitalized Overhead | Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information. |
Other Property and Equipment | Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment and software, office leasehold improvements, and office furniture and equipment) is stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment is depreciated under the straight-line method using estimated useful lives ranging from three to five years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its support equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. |
Revenue Payable | Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. |
Asset Retirement Obligations | Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. |
Business Combinations | Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under ASC 805, Business Combinations . Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. |
Goodwill | Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31 st . During 2016, we changed the date of our annual goodwill impairment assessment to October 1 st . With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. For purposes of assessing goodwill, the Company only has one reporting unit. As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016. We also performed our annual goodwill impairment test as of October 1, 2016. Neither of these tests resulted in an impairment. For both tests, the Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period. |
Oil and Natural Gas Sales | Oil and Natural Gas Sales: The Company derives revenue primarily from the sale of oil and natural gas produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. |
Major Customers | Major Customers: The Company sells production to a small number of customers as is customary in the industry. |
Lease Operating Expenses | Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities. |
Stock-Based Compensation | Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation. The compensation is recognized over the vesting period of the grant. |
Income Tax | Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before December 31, 2016 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2016 , the Company has not recognized any interest or penalties related to uncertain tax benefits. |
Financial Instruments | Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements) |
Commodity Derivative Instruments | Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. |
Transportation Commitment Charge | Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations. |
Recent Accounting Pronouncements | Recently Adopted Accounting Pronouncements: On January 2017, the FASB issued Accounting Standards Update ("ASU") 2017-01, "Clarifying the Definition of a Business" ("ASU 2017-01"), which clarifies the definition of a business in ASC 805. The amendments narrow the definition of a business and provide a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. Specifically, ASU 2017-01: i) provides a “screen” for determining when a set is not a business. The screen requires a determination that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business; ii) specifies that if the screen’s threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs and provides a framework to help entities evaluate whether both an input and a substantive process are present; iii) it removes the evaluation of whether a market participant could replace the missing elements; and iv) narrows the definition of the term “output.” ASU 2017-01 is effective in annual periods beginning after December 15, 2017, including interim periods therein. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted for transactions (i.e., acquisitions or dispositions) that occurred before the issuance date or effective date of the standard if the transactions were not reported in financial statements that have been issued or made available for issuance. We elected to early adopt this pronouncement effective October 1, 2016. As a result of adopting this pronouncement, we accounted for certain transactions as asset acquisitions which would have qualified as business combinations had we not adopted the standard. Recent Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, which must apply the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We plan to adopt this pronouncement effective January 1, 2017. Upon adoption of this standard, we will no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we will account for forfeitures when they occur. We will apply this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.3 million to retained earnings as of the date of adoption. The adoption of the other provisions is not expected to materially impact the consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. Currently, we have not identified any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of these ASUs as pertinent to certain sales contracts and in particular as they relates to disclosure requirements. There have been various updates issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations or cash flows. |
Organization and Summary of S28
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Concentration Risk [Line Items] | |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses consist of the following (in thousands): As of December 31, 2016 2015 Trade accounts payable $ 786 $ 3,046 Accrued well costs 42,779 32,123 Accrued G&A 4,292 1,404 Accrued other 4,596 — 52,453 36,573 |
Oil and Gas Revenues [Member] | |
Concentration Risk [Line Items] | |
Schedule of Customers With Balances Greater Than 10% of Total Receivables | The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil and natural gas revenue (“major customers”) for each of the periods presented are shown in the following table: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Company A 20% 15% 11% 13% Company B 20% * * * Company C 16% * * * Company D 13% * * * Company E * 57% 65% 54% Company F * 12% * * * less than 10% |
Accounts Receivable [Member] | |
Concentration Risk [Line Items] | |
Schedule of Customers With Balances Greater Than 10% of Total Receivables | Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table: As of December 31, 2016 2015 Company A 43% * Company B 23% 13% Company C 10% * Company D * 13% Company E * 13% * less than 10% |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Capitalized Costs | The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of December 31, 2016 2015 Oil and gas properties, full cost method: Costs of unproved properties and land, not subject to depletion: Lease acquisition and other costs $ 392,561 $ 89,122 Land 5,986 4,478 Subtotal, unproved properties and land 398,547 93,600 Costs of wells in progress 81,780 21,310 Costs of proved properties: Producing and non-producing 969,239 691,659 Less, accumulated depletion and full cost ceiling impairments (545,157 ) (280,368 ) Subtotal, proved properties, net 424,082 411,291 Costs of other property and equipment: Other property and equipment 5,063 1,270 Less, accumulated depreciation (736 ) (624 ) Subtotal, other property and equipment, net 4,327 646 Total property and equipment, net $ 908,736 $ 526,847 |
Schedule of Costs Incurred | Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Capitalized overhead $ 7,074 $ 1,091 $ 2,049 $ 1,230 Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Acquisition of property: Unproved $ 365,548 $ 38,779 $ 32,701 $ 15,002 Proved 152,363 51,085 51,400 33,795 Exploration costs 43,154 23,697 146,892 43,089 Development costs 87,782 17,742 4,957 111,238 Other property and equipment 7,506 395 741 9,315 Capitalized interest, capitalized G&A, and other 18,744 4,415 7,051 1,610 Total costs incurred $ 675,097 $ 136,113 $ 243,742 $ 214,049 |
Schedule of Capitalized Costs Excluded from Amortization | The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2016 (in thousands): Period Incurred Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, Total as of December 31, 2016 2015 2014 2013 and Prior Unproved leasehold acquisition costs $ 349,777 $ 37,765 $ 956 $ 430 $ 3,633 $ 392,561 Unproved development costs 46,268 — 4,170 — — 50,438 Total unevaluated costs $ 396,045 $ 37,765 $ 5,126 $ 430 $ 3,633 $ 442,999 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Greeley-Crescent Agreement [Member] | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price June 14, 2016 Consideration given: Cash $ 485,141 Net liabilities assumed, including asset retirement obligations 1,273 Total consideration given $ 486,414 Allocation of Purchase Price Proved oil and gas properties (1) $ 132,903 Unproved oil and gas properties 353,511 Total fair value of assets acquired $ 486,414 (1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rat e of 11.5% , a nd assumptions regarding the timing and amount of future development and operating costs. |
Schedule of Pro Forma Results | The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 Oil and natural gas revenues $ 110,635 $ 37,403 $ 147,643 Net loss $ (218,578 ) $ (122,577 ) $ 21,507 Net loss per common share Basic $ (1.10 ) $ (0.67 ) $ 0.13 Diluted $ (1.10 ) $ (0.67 ) $ 0.13 |
K.P. Kauffman Company, Inc. [Member] | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price October 20, 2015 Consideration given: Cash $ 35,045 Synergy Resources Corp. common stock (1) 49,840 Net liabilities assumed, including asset retirement obligations 284 Total consideration given $ 85,169 Allocation of Purchase Price Proved oil and gas properties (2) $ 46,333 Unproved oil and gas properties 37,766 Other assets, including accounts receivable 1,070 Total fair value of assets acquired $ 85,169 (1) The fair value of the consideration attributed to the common stock under ASC 805 was based on the Company's closing stock price on the measurement date of October 20, 2015 ( 4,418,413 shares at $11.28 per share). (2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 12% , and assumptions regarding the timing and amount of future development and operating costs. |
Schedule of Pro Forma Results | The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. (in thousands) Four Months Ended December 31, 2015 Year Ended August 31, 2015 Oil and natural gas revenues $ 35,389 $ 138,145 Net loss $ (122,529 ) $ 21,592 Net loss per common share Basic $ (1.12 ) $ 0.22 Diluted $ (1.12 ) $ 0.22 |
Depletion, depreciation and a31
Depletion, depreciation and accretion (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Costs and Disclosures [Abstract] | |
Schedule of Depletion, Depreciation and Amortization | Depletion, depreciation, and accretion consisted of the following (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Depletion of oil and gas properties $ 45,193 $ 18,371 $ 65,158 $ 32,132 Depreciation and accretion 1,485 405 711 826 Total DD&A Expense $ 46,678 $ 18,776 $ 65,869 $ 32,958 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Years Ended August 31, 2015 Beginning asset retirement obligation $ 13,400 $ 12,334 $ 4,730 Obligations incurred with development activities 773 1,590 1,372 Obligations assumed with acquisitions 2,230 229 1,913 Accretion expense 1,046 348 553 Obligations discharged with asset retirements and settlements (4,739 ) (1,101 ) — Revisions in previous estimates 3,748 — 3,766 Ending asset retirement obligation $ 16,458 $ 13,400 $ 12,334 |
Commodity Derivative Instrume33
Commodity Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Contracts | The Company’s commodity derivative contracts as of December 31, 2016 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per month) Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 60.00 Jan 1, 2017 - Dec 31, 2017 Collar 20,000 $ 45.00 70.00 Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 $ 65.00 Jan 1, 2017 - Apr 30, 2017 Put 20,000 $ 50.00 $ — May 1, 2017 - Aug 31, 2017 Put 20,000 $ 55.00 $ — Jan 1, 2017 - Dec 31, 2017 Collar 30,417 $ 40.00 $ 65.00 Jan 1, 2017 - Dec 31, 2017 Collar 15,208 $ 45.00 $ 65.00 Jan 1, 2017 - Dec 31, 2017 Collar 15,208 $ 45.00 $ 65.10 Settlement Period Derivative Average Volumes Floor Ceiling Natural Gas - NYMEX Henry Hub Jan 1, 2017 - Dec 31, 2017 Collar 100,000 $ 2.75 $ 4.00 Jan 1, 2017 - Dec 31, 2017 Collar 152,083 $ 2.75 $ 3.90 Sep 1, 2017 - Dec 31, 2017 Collar 91,500 $ 2.75 $ 4.10 Sep 1, 2017 - Dec 31, 2017 Collar 15,250 $ 3.00 $ 4.31 Feb 1, 2017 - Dec 31, 2017 Collar 109,309 $ 3.00 $ 4.30 Natural Gas - CIG Rocky Mountain Jan 1, 2017 - Apr 30, 2017 Collar 100,000 $ 2.80 $ 3.95 May 1, 2017 - Aug 31, 2017 Collar 110,000 $ 2.50 $ 3.06 Jan 1, 2017 - Dec 31, 2017 Collar 200,000 $ 2.50 $ 3.27 Jan 1, 2017 - Dec 31, 2017 Collar 100,000 $ 2.60 $ 3.20 |
Schedule of Fair Value of Derivatives | The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands): As of December 31, 2016 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity Derivative contracts Current assets $ 2,045 $ (1,748 ) $ 297 Commodity Derivative contracts Noncurrent assets $ — $ — $ — Commodity Derivative contracts Current liabilities $ 4,622 $ (1,748 ) $ 2,874 Commodity Derivative contracts Noncurrent liabilities $ — $ — $ — As of December 31, 2015 Underlying Commodity Balance Sheet Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Net Amounts of Assets and Liabilities Presented in the Commodity Derivative contracts Current assets $ 6,719 $ (147 ) $ 6,572 Commodity Derivative contracts Noncurrent assets $ 3,354 $ (358 ) $ 2,996 Commodity Derivative contracts Current liabilities $ 147 $ (147 ) $ — Commodity Derivative contracts Noncurrent liabilities $ 358 $ (358 ) $ — |
Schedule of Loss Recognized in Statements of Operations | The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Realized gain (loss) on commodity derivatives $ 2,355 $ 1,577 $ 30,466 $ (2,138 ) Unrealized gain (loss) on commodity derivatives (10,105 ) 4,905 1,790 2,459 Total gain (loss) $ (7,750 ) $ 6,482 $ 32,256 $ 321 |
Schedule of Hedge Realized Gains (Losses) | The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Monthly settlement 4,396 2,331 $ 11,212 $ (2,138 ) Previously incurred premiums attributable to settled commodity contracts (2,041 ) (754 ) (1,255 ) — Early liquidation — — 20,509 — Total realized gain (loss) $ 2,355 $ 1,577 $ 30,466 $ (2,138 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured on a Recurring Basis | The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 by level within the fair value hierarchy (in thousands): Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 297 $ — $ 297 Commodity derivative liability $ — $ 2,874 $ — $ 2,874 Fair Value Measurements at December 31, 2015 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 9,568 $ — $ 9,568 Commodity derivative liability $ — $ — $ — $ — |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Interest and Debt Expense [Abstract] | |
Schedule of the Components of Interest Expense | The components of interest expense are (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Revolving credit facility $ 154 $ 661 $ 2,776 $ 986 Note payable 3,940 — — — Amortization of debt issuance costs 1,638 431 853 448 Less: interest capitalized (5,732 ) (1,092 ) (3,384 ) (1,434 ) Interest expense, net $ — $ — $ 245 $ — |
Shareholders' Equity (Tables)
Shareholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Classes of Stock | The Company's classes of stock are summarized as follows: As of December 31, 2016 2015 Preferred stock, shares authorized 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil Common stock, shares authorized 300,000,000 300,000,000 Common stock, par value $ 0.001 $ 0.001 Common stock, shares issued and outstanding 200,647,572 110,033,601 |
Schedule of Common Stock Sold in Public Offering | A summary of the transactions is shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering. Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of common shares sold 90,275,000 — 18,613,952 — Offering price per common share $ 6.02 $ — $ 10.75 $ — Net proceeds (in thousands) $ 543,400 $ — $ 190,845 $ — |
Schedule of Common Stock Issued For Acquisition of Mineral Interests and Services | The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction. Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of common shares issued for mineral property leases — 37,051 995,672 357,901 Number of common shares issued for acquisitions — 4,418,413 4,648,136 872,483 Total common shares issued — 4,455,464 5,643,808 1,230,384 Average price per common share $ — $ 11.28 $ 10.67 $ 9.09 Aggregate value of shares issues (in thousands) $ — $ 50,265 $ 60,221 $ 11,184 |
Schedule of Issued and Outstanding Common Stock Warrants | The following table summarizes activity for common stock warrants for the periods presented: Number of Shares Issuable Upon Warrant Exercise Weighted-Average Exercise Price Per Share Outstanding, August 31, 2014 2,562,473 $ 6.00 Exercised (2,562,473 ) $ 6.00 Forfeited / Expired — $ — Outstanding, August 31, 2015 — $ — Exercised — $ — Forfeited / Expired — $ — Outstanding, December 31, 2015 — $ — Exercised — $ — Forfeited / Expired — $ — Outstanding, December 31, 2016 — $ — |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Reconciliation of Weighted-average Shares Outstanding Basic and Diluted | The following table sets forth the share calculation of diluted earnings per share: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Weighted-average shares outstanding - basic 173,774,035 107,789,554 94,628,665 76,214,737 Potentially dilutive common shares from: Stock options — — 672,493 479,222 Restricted stock units and stock bonus shares — — 18,111 — Performance-vested stock units — — — — Warrants — — — 1,114,095 Weighted-average shares outstanding - diluted 173,774,035 107,789,554 95,319,269 77,808,054 |
Schedule of Potentially Dilutive Securities | The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above as such securities had an anti-dilutive effect on earnings per share: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Potentially dilutive common shares from: Stock options 6,001,500 5,056,000 2,785,500 533,000 Restricted stock units and stock bonus shares 890,336 915,867 145,000 — Performance-vested stock units 1 478,510 — — — Warrants — — — — Total 7,370,346 5,971,867 2,930,500 533,000 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Stock-based Compensation Expense Recognized | The amount of stock-based compensation was as follows (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Stock options $ 5,417 $ 2,161 $ 4,741 $ 1,767 Performance stock units 1,047 — — — Restricted stock units and stock bonus shares 4,232 7,162 2,950 1,201 Total stock-based compensation 10,696 9,323 7,691 2,968 Less: stock-based compensation capitalized (1,205 ) (892 ) (778 ) (514 ) Total stock-based compensation expense $ 9,491 $ 8,431 $ 6,913 $ 2,454 |
Schedule of Employee Stock Options Granted During the Period | During the respective periods, the Company granted the following stock options: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Number of options to purchase common shares 1,067,500 1,142,500 2,377,500 433,000 Weighted-average exercise price $ 7.19 $ 10.84 $ 11.55 $ 10.37 Term (in years) 10 years 10 years 10 years 10 years Vesting Period (in years) 3 - 5 years 3.7-5 years 3-5 years 5 years Fair Value (in thousands) $ 3,860 $ 6,591 $ 13,266 $ 3,009 |
Schedule of Assumptions Used In Valuing Stock Options | The assumptions used in valuing stock options granted during each of the periods presented were as follows: Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Expected term 6.4 years 6.5 years 6.5 years 6.7 years Expected volatility 55 % 53 % 47 % 73 % Risk free rate 1.25 - 2.00% 1.8 - 2.0% 1.4 - 2.0% 1.8 - 2.3% Expected dividend yield — % — % — % — % |
Summary of Stock Option Activity Under Stock Option | The following table summarizes activity for stock options for the periods presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2013 1,820,000 $ 4.88 8.7 years $ 8,160 Granted 433,000 10.37 Exercised (61,000 ) 3.71 481 Expired (25,000 ) 10.32 Outstanding, August 31, 2014 2,167,000 5.94 8.0 years 16,287 Granted 2,377,500 11.55 Exercised (258,000 ) 3.81 2,103 Forfeited (110,000 ) 4.97 Outstanding, August 31, 2015 4,176,500 9.29 8.6 years 8,187 Granted 1,142,500 10.84 Exercised (188,000 ) 6.56 981 Expired (60,000 ) 11.74 Forfeited (15,000 ) 11.68 Outstanding, December 31, 2015 5,056,000 9.71 8.7 years 4,351 Granted 1,067,500 7.19 Exercised (20,000 ) 3.91 117 Expired — — Forfeited (102,000 ) 10.40 Outstanding, December 31, 2016 6,001,500 $ 9.27 8.0 years $ 6,515 Outstanding, Exercisable at December 31, 2016 2,406,100 $ 8.42 7.0 years $ 4,297 Outstanding, Vested and Expected to Vest at December 31, 2016 5,937,601 $ 9.24 7.9 years $ 6,511 |
Schedule of Issued and Outstanding Stock Options | The following table summarizes information about issued and outstanding stock options as of December 31, 2016 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Remaining Contractual Life Weighted-Average Exercise Price per Share Options Weighted-Average Exercise Price per Share Under $5.00 630,000 4.7 years $ 3.50 589,000 $ 3.48 $5.00 - $6.99 1,012,000 7.9 years 6.38 430,000 6.51 $7.00 - $10.99 1,617,500 8.5 years 9.34 383,900 9.72 $11.00 - $13.46 2,742,000 8.4 years 11.61 1,003,200 11.63 Total 6,001,500 8.0 years $ 9.27 2,406,100 $ 8.42 |
Schedule of Unrecognized Compensation Cost | The estimated unrecognized compensation cost from stock options not vested as of December 31, 2016 , which will be recognized ratably over the remaining vesting phase, is as follows: Unrecognized compensation, net of estimated forfeitures (in thousands) $ 15,330 Remaining vesting phase 3.2 years |
Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Unrecognized Compensation Cost | The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2016 , which will be recognized ratably over the remaining vesting phase, is as follows: Unrecognized compensation, net of estimated forfeitures (in thousands) $ 6,711 Remaining vesting phase 2.8 years |
Summary of Restricted Stock Awards | The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented: Number of Weighted-Average Not vested, August 31, 2013 46,667 $ 6.75 Granted 343,780 11.34 Vested (97,114 ) 11.38 Forfeited — — Not vested, August 31, 2014 293,333 10.60 Granted 547,699 11.17 Vested (208,532 ) 11.09 Forfeited — — Not vested, August 31, 2015 632,500 10.93 Granted 919,604 10.08 Vested (636,237 ) 10.13 Forfeited — — Not vested, December 31, 2015 915,867 10.63 Granted 464,533 7.66 Vested (424,483 ) 9.92 Forfeited (65,581 ) 8.99 Not vested, December 31, 2016 890,336 $ 9.55 |
Performance-vested stock units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Assumptions Used In Valuing Stock Options | The assumptions used in valuing the PSUs granted were as follows: Year Ended December 31, 2016 Weighted-average expected term 2.7 years Weighted-average expected volatility 58 % Weighted-average risk free rate 0.87 % |
Schedule of Nonvested Share Activity | A summary of the status and activity of PSUs is presented in the following table: Number of Units 1 Weighted-Average Grant-Date Fair Value Not vested, December 31, 2015 — $ — Granted 490,713 8.10 Vested — — Forfeited (12,203 ) 8.22 Not vested, December 31, 2016 478,510 $ 8.09 1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the vesting condition. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Taxes | The income tax provision is comprised of the following (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Current: Federal $ 106 $ — $ (4 ) $ 4 State — — (111 ) 111 Total current income tax expense (benefit) $ 106 $ — $ (115 ) $ 115 Deferred: Federal $ (74,099 ) $ (45,332 ) $ 10,820 $ 13,748 State (6,651 ) (4,074 ) 972 1,151 Total deferred income tax (benefit) expense $ (80,750 ) $ (49,406 ) $ 11,792 $ 14,899 Valuation allowance 80,750 39,399 — — Income tax expense (benefit) $ 106 $ (10,007 ) $ 11,677 $ 15,014 |
Schedule of Reconciliation of Income Taxes | A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Federal income tax at statutory rate $ (74,489 ) $ (45,200 ) $ 10,105 $ 14,915 State income taxes, net of federal tax (6,685 ) (4,062 ) 908 1,341 Statutory depletion (287 ) (150 ) (451 ) (1,266 ) Stock-based compensation 383 — 92 — Non-deductible compensation — — 850 125 Valuation allowance 80,750 39,399 — — Other 434 6 173 (101 ) Income tax provision $ 106 $ (10,007 ) $ 11,677 $ 15,014 Effective rate expressed as a percentage — % 8 % 39 % 34 % |
Schedule of Deferred Tax Assets and Liabilities | The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands): As of December 31, 2016 2015 Deferred tax assets (liabilities): Net operating loss carryforward $ 47,462 $ 11,855 Stock-based compensation 5,576 3,304 Basis of oil and gas properties 62,707 23,656 Statutory depletion 4,028 2,802 Unrealized (gain) loss on commodity derivative 1,334 (2,410 ) Other (958 ) 192 120,149 39,399 Valuation allowance on tax assets (120,149 ) (39,399 ) Deferred tax asset (liability), net $ — $ — |
Other Commitments and Conting40
Other Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual Commitment Over the Next Five Years | Our commitments over the next five years, excluding the contingent commitment described in the preceding paragraph, are as follows: Year ending December 31, Oil (MBbls) 2017 3,944 2018 4,255 2019 4,255 2020 3,700 2021 1,672 Thereafter — Total 17,826 |
Operating Leases of Lessee Disclosure | A schedule of the minimum lease payments under non-cancelable operating leases as of December 31, 2016 follows (in thousands): 2017 398 2018 840 2019 859 2020 878 2021 875 Thereafter 477 Total 4,327 |
Supplemental Schedule of Info41
Supplemental Schedule of Information to the Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Supplemental Information to the Statements of Cash Flows | The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands): Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Supplemental cash flow information: Interest paid $ 3,779 $ 683 $ 2,817 $ 989 Income taxes paid (refunded) $ 106 $ (150 ) $ 202 $ — Non-cash investing and financing activities: Accrued well costs payable $ 42,779 $ 31,414 $ 33,071 $ 71,849 Assets acquired in exchange for common stock $ — $ 50,265 $ 60,221 $ 11,184 Obligations incurred with development activities $ 773 $ 1,819 $ 7,051 $ 1,610 Obligations assumed with acquisitions $ 2,230 $ — $ — $ — Obligations discharged with asset retirements and divestitures $ (4,739 ) $ — $ — $ — |
Unaudited Oil and Gas Reserve42
Unaudited Oil and Gas Reserves Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year | The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented: Oil (MBbl) Natural Gas (MMcf) MBOE Balance, August 31, 2013 7,047 40,690 13,829 Revision of previous estimates 83 3,047 591 Purchase of reserves in place 1,028 5,956 2,021 Extensions, discoveries, and other additions 9,142 49,289 17,357 Sale of reserves in place (35 ) (56 ) (44 ) Production (941 ) (3,747 ) (1,566 ) Balance, August 31, 2014 16,324 95,179 32,188 Revision of previous estimates (1,699 ) (4,889 ) (2,513 ) Purchase of reserves in place 4,201 21,957 7,860 Extensions, discoveries, and other additions 11,465 73,392 23,696 Sale of reserves in place (629 ) (4,337 ) (1,352 ) Production (1,970 ) (7,344 ) (3,194 ) Balance, August 31, 2015 27,692 173,958 56,685 Revision of previous estimates (10,917 ) (38,931 ) (17,407 ) Purchase of reserves in place 4,380 58,959 14,207 Extensions, discoveries, and other additions 8,263 62,301 18,647 Sale of reserves in place (2,297 ) (14,149 ) (4,655 ) Production (742 ) (3,468 ) (1,320 ) Balance, December 31, 2015 26,379 238,670 66,157 Revision of previous estimates (7,788 ) (80,549 ) (21,213 ) Purchase of reserves in place 23,141 197,103 55,991 Extensions, discoveries, and other additions 1,457 13,018 3,627 Sale of reserves in place (2,900 ) (24,235 ) (6,939 ) Production (2,257 ) (12,086 ) (4,271 ) Balance, December 31, 2016 38,032 331,921 93,352 Proved developed and undeveloped reserves: Developed at August 31, 2014 6,616 38,162 12,977 Undeveloped at August 31, 2014 9,708 57,017 19,211 Balance, August 31, 2014 16,324 95,179 32,188 Developed at August 31, 2015 7,393 46,026 15,064 Undeveloped at August 31, 2015 20,299 127,932 41,621 Balance, August 31, 2015 27,692 173,958 56,685 Developed at December 31, 2015 8,410 56,751 17,868 Undeveloped at December 31, 2015 17,969 181,919 48,289 Balance, December 31, 2015 26,379 238,670 66,157 Developed at December 31, 2016 7,435 62,570 17,863 Undeveloped at December 31, 2016 30,597 269,351 75,489 Balance, December 31, 2016 38,032 331,921 93,352 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands): As of December 31, As of August 31, 2016 2015 2015 2014 Future cash inflow $ 2,180,673 $ 1,710,610 $ 2,046,615 $ 1,839,987 Future production costs (644,093 ) (462,097 ) (653,009 ) (395,019 ) Future development costs (584,537 ) (340,449 ) (510,720 ) (412,517 ) Future income tax expense (90,195 ) (108,172 ) (144,399 ) (252,925 ) Future net cash flows 861,848 799,892 738,487 779,526 10% annual discount for estimated timing of cash flows (427,587 ) (408,939 ) (372,658 ) (376,827 ) Standardized measure of discounted future net cash flows $ 434,261 $ 390,953 $ 365,829 $ 402,699 |
Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves | The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials: Oil (Bbl) Natural Gas (Mcf) December 31, 2016 (Average) $ 36.07 $ 2.44 December 31, 2015 (Average) $ 41.33 $ 2.60 August 31, 2015 (Average) $ 53.27 $ 3.28 August 31, 2014 (Average) $ 89.48 $ 5.03 |
Schedule of Changes in the Standardized Measure for Discounted Cash Flows | Year Ended December 31, 2016 Four Months Ended December 31, 2015 Year Ended August 31, 2015 2014 Standardized measure, beginning of period $ 390,953 $ 365,829 $ 402,699 $ 181,732 Sale and transfers, net of production costs (81,468 ) (25,222 ) (98,486 ) (86,808 ) Net changes in prices and production costs (64,387 ) (81,968 ) (233,051 ) 15,828 Extensions, discoveries, and improved recovery 18,795 116,343 173,918 300,087 Changes in estimated future development costs (6,016 ) (7,195 ) 10,002 (20,817 ) Previously estimated development costs incurred during the period 62,502 5,923 4,957 15,000 Revision of quantity estimates (110,306 ) (36,820 ) (38,340 ) 4,589 Accretion of discount 44,703 14,610 57,629 23,612 Net change in income taxes 5,104 25,263 58,547 (76,616 ) Divestitures of reserves (26,839 ) (43,754 ) (19,234 ) (925 ) Purchase of reserves in place 228,855 77,024 56,795 47,017 Changes in timing and other (27,635 ) (19,080 ) (9,607 ) — Standardized measure, end of period $ 434,261 $ 390,953 $ 365,829 $ 402,699 |
Unaudited Quarterly Financial43
Unaudited Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Unaudited Quarterly Financial Data | The Company’s unaudited quarterly financial information is as follows (in thousands, except share data): Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 18,273 $ 23,947 $ 26,234 $ 38,695 Expenses 71,356 172,157 45,887 29,324 Operating income (loss) (53,083 ) (148,210 ) (19,653 ) 9,371 Other income (expense) 1,682 (5,537 ) 417 (4,070 ) Income (loss) before income taxes (51,401 ) (153,747 ) (19,236 ) 5,301 Income tax provision (benefit) — 101 5 — Net income (loss) $ (51,401 ) $ (153,848 ) $ (19,241 ) $ 5,301 Net income (loss) per common share: (1) Basic $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Diluted (2) $ (0.42 ) $ (0.89 ) $ (0.10 ) $ 0.03 Weighted-average shares outstanding: Basic 121,392,736 172,013,551 200,515,555 200,585,800 Diluted 121,392,736 172,013,551 200,515,555 201,254,678 Year Ended December 31, 2015 First Quarter (3) Second Quarter (3) Third Quarter (3) Fourth Quarter (3) Revenues $ 18,938 $ 28,286 $ 33,378 $ 25,448 Expenses 24,086 31,303 128,366 79,018 Operating income (5,148 ) (3,017 ) (94,988 ) (53,570 ) Other income (expense) 3,446 (4,474 ) 6,547 5,383 Income before income taxes (1,702 ) (7,491 ) (88,441 ) (48,187 ) Income tax provision (709 ) (2,903 ) (10,520 ) — Net income $ (993 ) $ (4,588 ) $ (77,921 ) $ (48,187 ) Net income per common share: (1) Basic $ (0.01 ) $ (0.04 ) $ (0.74 ) $ (0.44 ) Diluted (2) $ (0.01 ) $ (0.04 ) $ (0.74 ) $ (0.44 ) Weighted-average shares outstanding: Basic 97,241,301 104,562,662 105,100,849 108,664,875 Diluted 97,241,301 104,562,662 105,100,849 108,664,875 The Company’s unaudited financial information for the four months ended December 31, 2014 is as follows (in thousands, except share data): Four Months Ended December 31, 2014 Revenues $ 52,931 Expenses 38,047 Operating income 14,884 Other income (expense) 27,717 Income before income taxes 42,601 Income tax provision 15,802 Net income $ 26,799 Net income per common share: Basic $ 0.34 Diluted (2) $ 0.33 Weighted-average shares outstanding: Basic 79,971,698 Diluted 80,693,410 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. 3 The Company has recast this quarterly financial information for the year ended December 31, 2015 to reflect the change in the Company's fiscal year. |
Organization and Summary of S44
Organization and Summary of Significant Accounting Policies (Details) $ in Thousands | 4 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($)segment | Dec. 31, 2015USD ($) | Aug. 31, 2015USD ($) | Aug. 31, 2014USD ($) | Jan. 01, 2017USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||
Number of operating segments | segment | 1 | |||||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | 10.00% | |||
Full cost ceiling impairment | $ 125,230 | $ 215,223 | $ 16,000 | $ 0 | ||
Remittance period | 30 days | |||||
Accounts Payable, Current [Abstract] | ||||||
Trade accounts payable | 3,046 | $ 786 | $ 3,046 | |||
Accrued well costs | 32,123 | 42,779 | 32,123 | |||
Accrued G&A | 1,404 | 4,292 | 1,404 | |||
Accrued other | 0 | 4,596 | 0 | |||
Accounts payable and accrued expenses | 36,573 | 52,453 | 36,573 | |||
Concentration Risk [Line Items] | ||||||
Cash held in escrow and other deposits | $ 0 | $ 18,248 | $ 0 | |||
Accumulated Earnings (Deficit) [Member] | Subsequent Event [Member] | Accounting Standards Update 2016-09 [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Cumulative effect of adoption | $ 300 | |||||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company A [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 15.00% | 20.00% | 11.00% | 13.00% | ||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company B [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 20.00% | |||||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company C [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 16.00% | |||||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company D [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 13.00% | |||||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company E [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 57.00% | 65.00% | 54.00% | |||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company F [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 12.00% | |||||
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Company A [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 43.00% | |||||
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Company B [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 23.00% | 13.00% | ||||
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Company C [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 10.00% | |||||
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Company D [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 13.00% | |||||
Customer Concentration Risk [Member] | Accounts Receivable [Member] | Company E [Member] | ||||||
Concentration Risk [Line Items] | ||||||
Risk percentage | 13.00% |
Property and Equipment (Narrati
Property and Equipment (Narrative) (Details) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($)$ / bbl$ / Mcf | Dec. 31, 2016USD ($)$ / bbl$ / Mcf | Aug. 31, 2015USD ($)$ / bbl$ / Mcf | Aug. 31, 2014USD ($)$ / bbl$ / Mcf | |
Reserve Quantities [Line Items] | ||||
Full cost ceiling impairment | $ 125,230 | $ 215,223 | $ 16,000 | $ 0 |
Unproved properties impairment | 125,230 | 215,223 | 16,000 | 0 |
Unproved Properties [Member] | ||||
Reserve Quantities [Line Items] | ||||
Unproved properties impairment | $ 0 | $ 18,900 | $ 15,400 | $ 0 |
Oil (Bbl) [Member] | ||||
Reserve Quantities [Line Items] | ||||
Prices per unit | $ / bbl | 41.33 | 36.07 | 53.27 | 89.48 |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Prices per unit | $ / Mcf | 2.60 | 2.44 | 3.28 | 5.03 |
Property and Equipment (Schedul
Property and Equipment (Schedule of Capitalized Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | $ 398,547 | $ 93,600 |
Costs of wells in progress | 81,780 | 21,310 |
Costs of proved properties: | ||
Producing and non-producing | 969,239 | 691,659 |
Less, accumulated depletion and full cost ceiling impairments | (545,157) | (280,368) |
Subtotal, proved properties, net | 424,082 | 411,291 |
Costs of other property and equipment: | ||
Other property and equipment | 5,063 | 1,270 |
Less, accumulated depreciation | (736) | (624) |
Subtotal, other property and equipment, net | 4,327 | 646 |
Total property and equipment, net | 908,736 | 526,847 |
Land [Member] | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | 5,986 | 4,478 |
Lease acquisition and other costs [Member] | ||
Costs of unproved properties and land, not subject to depletion: | ||
Unproved properties and land | $ 392,561 | $ 89,122 |
Property and Equipment (Sched47
Property and Equipment (Schedule of Capitalized Overhead) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Property, Plant and Equipment [Abstract] | ||||
Capitalized overhead | $ 1,091 | $ 7,074 | $ 2,049 | $ 1,230 |
Property and Equipment (Sched48
Property and Equipment (Schedule of Costs Incurred) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Acquisition of property: | ||||
Unproved | $ 38,779 | $ 365,548 | $ 32,701 | $ 15,002 |
Proved | 51,085 | 152,363 | 51,400 | 33,795 |
Exploration costs | 23,697 | 43,154 | 146,892 | 43,089 |
Development costs | 17,742 | 87,782 | 4,957 | 111,238 |
Other property and equipment | 395 | 7,506 | 741 | 9,315 |
Asset retirement obligation | 4,415 | 18,744 | 7,051 | 1,610 |
Total costs Incurred | $ 136,113 | $ 675,097 | $ 243,742 | $ 214,049 |
Property and Equipment (Sched49
Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | $ 37,765 | $ 396,045 | $ 5,126 | $ 430 | $ 3,633 |
Unevaluated costs, not subject to amortization | 442,999 | ||||
Unproved leasehold acquisition costs [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | 37,765 | 349,777 | 956 | 430 | 3,633 |
Unevaluated costs, not subject to amortization | 392,561 | ||||
Unevaluated development costs [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Total unevaluated costs | $ 0 | 46,268 | $ 4,170 | $ 0 | $ 0 |
Unevaluated costs, not subject to amortization | $ 50,438 |
Acquisitions and Divestitures50
Acquisitions and Divestitures (Narrative) (Details) $ in Thousands | Jun. 14, 2016USD ($)abbl / d | May 02, 2016USD ($)aBoe | Feb. 04, 2016USD ($) | Oct. 20, 2015USD ($)abbl / dshares | Oct. 31, 2016USD ($)acquisition | Aug. 31, 2016USD ($)acquisition | Jun. 30, 2016USD ($)aBoewell | Dec. 31, 2015USD ($)Boeshares | Dec. 31, 2016USD ($)Boeshares | Aug. 31, 2015USD ($)Boeshares | Aug. 31, 2014USD ($)Boeshares |
Business Acquisition [Line Items] | |||||||||||
Production of BOE (in Boe's) | Boe | 1,320,000 | 4,271,000 | 3,194,000 | 1,566,000 | |||||||
Cash held in escrow and other deposits | $ 0 | $ 18,248 | |||||||||
Business acquisition, shares issued | shares | 4,418,413 | 0 | 4,648,136 | 872,483 | |||||||
Net proceeds from sales of oil and gas properties and land | $ 0 | $ 25,350 | $ 6,239 | $ 704 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Adams County, Colorado [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Mineral acres, net | a | 3,700 | ||||||||||
Production of BOE (in Boe's) | Boe | 200 | ||||||||||
Cash held in escrow and other deposits | $ 500 | ||||||||||
Number of productive wells, net | well | 107 | ||||||||||
Net proceeds from sales of oil and gas properties and land | $ 24,700 | ||||||||||
Series of Individually Immaterial Business Acquisitions [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of acquisitions | acquisition | 2 | 2 | |||||||||
Total purchase price | $ 10,000 | $ 9,600 | $ 3,900 | ||||||||
Proved oil and gas properties | 8,600 | ||||||||||
Unproved oil and gas properties | $ 1,400 | ||||||||||
Greeley-Crescent Agreement [Member] | Wattenberg Field [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total purchase price | $ 505,000 | ||||||||||
Mineral acres, gross | a | 72,000 | ||||||||||
Mineral acres, net | a | 33,100 | ||||||||||
Production of BOE (in Boe's) | Boe | 2,400 | ||||||||||
Greeley-Crescent Agreement [Member] | D-J Basin, Colorado [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total purchase price | $ 486,414 | ||||||||||
Cash | $ 485,141 | ||||||||||
Mineral acres, net | a | 33,100 | ||||||||||
Cash held in escrow and other deposits | $ 18,200 | ||||||||||
Production of barrels of oil equivalent per day | bbl / d | 800 | ||||||||||
Transaction costs | $ 500 | ||||||||||
Proved oil and gas properties | 132,903 | ||||||||||
Unproved oil and gas properties | $ 353,511 | ||||||||||
Pro forma revenue since acquisition date | 5,300 | 4,400 | |||||||||
K.P. Kauffman Company, Inc. [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total purchase price | $ 85,169 | ||||||||||
Cash | $ 35,045 | ||||||||||
Mineral acres, net | a | 4,300 | ||||||||||
Production of barrels of oil equivalent per day | bbl / d | 1,200 | ||||||||||
Proved oil and gas properties | $ 46,333 | ||||||||||
Unproved oil and gas properties | $ 37,766 | ||||||||||
Business acquisition, shares issued | shares | 4,418,413 | ||||||||||
Synergy Resources Corp. Common Stock | $ 49,840 | ||||||||||
Pro forma revenue since acquisition date | $ 1,100 | $ 5,100 | $ 4,500 | $ 800 |
Acquisitions and Divestitures51
Acquisitions and Divestitures (Schedule of Fair Value of Acquisition) (Details) - USD ($) $ / shares in Units, $ in Thousands | Jun. 14, 2016 | Oct. 20, 2015 | Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 |
Preliminary Allocation of Purchase Price | ||||||
Goodwill | $ 40,711 | $ 40,711 | ||||
Business acquisition, shares issued | 4,418,413 | 0 | 4,648,136 | 872,483 | ||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||||
K.P. Kauffman Company, Inc. [Member] | ||||||
Preliminary Purchase Price | ||||||
Cash | $ 35,045 | |||||
Synergy Resources Corp. Common Stock | 49,840 | |||||
Net liabilities assumed, including asset retirement obligations | 284 | |||||
Total consideration given | 85,169 | |||||
Preliminary Allocation of Purchase Price | ||||||
Proved oil and gas properties | 46,333 | |||||
Unproved oil and gas properties | 37,766 | |||||
Other assets, including accounts receivable | 1,070 | |||||
Total fair value of oil and gas properties acquired | $ 85,169 | |||||
Business acquisition, shares issued | 4,418,413 | |||||
Closing stock price (in dollars per share) | $ 11.28 | |||||
Net cash flows, discount rate (percent) | 12.00% | |||||
D-J Basin, Colorado [Member] | Greeley-Crescent Agreement [Member] | ||||||
Preliminary Purchase Price | ||||||
Cash | $ 485,141 | |||||
Net liabilities assumed, including asset retirement obligations | 1,273 | |||||
Total consideration given | 486,414 | |||||
Preliminary Allocation of Purchase Price | ||||||
Proved oil and gas properties | 132,903 | |||||
Unproved oil and gas properties | 353,511 | |||||
Total fair value of oil and gas properties acquired | $ 486,414 | |||||
Net cash flows, discount rate (percent) | 11.50% |
Acquisitions and Divestitures52
Acquisitions and Divestitures (Schedule of Pro Forma Results) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | |
K.P. Kauffman Company, Inc. [Member] | |||
Business Acquisition [Line Items] | |||
Oil and gas revenues | $ 35,389 | $ 138,145 | |
Net income | $ (122,529) | $ 21,592 | |
Net (loss) income per common share | |||
Basic (in dollars per share) | $ (1.12) | $ 0.22 | |
Diluted (in dollars per share) | $ (1.12) | $ 0.22 | |
D-J Basin, Colorado [Member] | Greeley-Crescent Agreement [Member] | |||
Business Acquisition [Line Items] | |||
Oil and gas revenues | $ 37,403 | $ 110,635 | $ 147,643 |
Net income | $ (122,577) | $ (218,578) | $ 21,507 |
Net (loss) income per common share | |||
Basic (in dollars per share) | $ (0.67) | $ (1.10) | $ 0.13 |
Diluted (in dollars per share) | $ (0.67) | $ (1.10) | $ 0.13 |
Depletion, depreciation and a53
Depletion, depreciation and accretion (Details) Boe in Thousands, $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($)Boe$ / Boe | Dec. 31, 2016USD ($)Boe$ / Boe | Aug. 31, 2015USD ($)Boe$ / Boe | Aug. 31, 2014USD ($)Boe$ / Boe | |
Other Costs and Disclosures [Abstract] | ||||
Depletion of oil and gas properties | $ 18,371 | $ 45,193 | $ 65,158 | $ 32,132 |
Depreciation and accretion | 405 | 1,485 | 711 | 826 |
Total DDA Expense | $ 18,776 | $ 46,678 | $ 65,869 | $ 32,958 |
Production of BOE (in Boe's) | Boe | 1,320 | 4,271 | 3,194 | 1,566 |
Percentage of total reserves | 2.00% | 4.40% | 5.30% | 4.60% |
DDA expense per BOE (in dollars per BOE) | $ / Boe | 14.22 | 10.93 | 20.62 | 21.05 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning asset retirement obligation | $ 12,334 | $ 13,400 | $ 4,730 |
Obligations incurred with development activities | 1,590 | 773 | 1,372 |
Obligations assumed with acquisitions | 229 | 2,230 | 1,913 |
Accretion expense | (348) | (1,046) | (553) |
Obligations discharged with asset retirements and settlements | (1,101) | (4,739) | 0 |
Revisions in previous estimates | 0 | 3,748 | 3,766 |
Ending asset retirement obligation | $ 13,400 | $ 16,458 | $ 12,334 |
Revolving Credit Facility (Deta
Revolving Credit Facility (Details) | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2015 | Oct. 14, 2016USD ($) | Oct. 13, 2016USD ($) | |
Line of Credit Facility [Line Items] | |||||
Amount outstanding | $ 78,000,000 | $ 0 | |||
Line of Credit [Member] | Revolving Credit Facility [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Total borrowing commitment | 500,000,000 | ||||
Borrowing base | 160,000,000 | $ 160,000,000 | $ 145,000,000 | ||
Amount outstanding | $ 0 | ||||
Average interest rate | 2.50% | 2.63% | 2.50% | ||
Term of covenants | 5 years | ||||
Maximum funded debt to EBITDAX | 4 | ||||
Current ratio covenant | 1 | ||||
Line of Credit [Member] | Letter of Credit [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Amount outstanding | $ 500,000 |
Notes Payable (Details)
Notes Payable (Details) - Senior Notes [Member] - 9% Senior Notes Due 2021 [Member] | Jun. 14, 2016USD ($) |
Debt Instrument [Line Items] | |
Face value of promissory note | $ 80,000,000 |
Debt instrument stated interest rate (percent) | 9.00% |
Proceeds from sale of Senior Notes | $ 75,200,000 |
Debt issuance costs | $ 4,800,000 |
Debt instrument effective interest rate (percent) | 10.50% |
2018 [Member] | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 104.50% |
2019 [Member] | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 102.25% |
2020 [Member] | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 100.00% |
Prior to December 14, 2018 [Member] | |
Debt Instrument [Line Items] | |
Redemption price (percent) | 109.00% |
Amount of principal that can be redeemed (percent) | 35.00% |
Commodity Derivative Instrume57
Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details) | 12 Months Ended |
Dec. 31, 2016MMBTU / mobbl / mo$ / bbl$ / MMBTU | |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 30,417 |
Floor Price | $ / bbl | 40 |
Ceiling Price | $ / bbl | 60 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 20,000 |
Floor Price | $ / bbl | 45 |
Ceiling Price | $ / bbl | 70 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 30,417 |
Floor Price | $ / bbl | 40 |
Ceiling Price | $ / bbl | 65 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Put [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 20,000 |
Floor Price | $ / bbl | 50 |
Ceiling Price | $ / bbl | 0 |
Crude Oil [Member] | May 1, 2017 - Aug 31, 2017 [Member] | Put [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 20,000 |
Floor Price | $ / bbl | 55 |
Ceiling Price | $ / bbl | 0 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 30,417 |
Floor Price | $ / bbl | 40 |
Ceiling Price | $ / bbl | 65 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 15,208 |
Floor Price | $ / bbl | 45 |
Ceiling Price | $ / bbl | 65 |
Crude Oil [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volume (BBl's per month) | bbl / mo | 15,208 |
Floor Price | $ / bbl | 45 |
Ceiling Price | $ / bbl | 65.10 |
Natural Gas [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 100,000 |
Floor Price | 2.75 |
Ceiling Price | 4 |
Natural Gas [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 152,083 |
Floor Price | 2.75 |
Ceiling Price | 3.90 |
Natural Gas [Member] | Sep 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 91,500 |
Floor Price | 2.75 |
Ceiling Price | 4.10 |
Natural Gas [Member] | Sep 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 15,250 |
Floor Price | 3 |
Ceiling Price | 4.31 |
Natural Gas [Member] | Feb 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 109,309 |
Floor Price | 3 |
Ceiling Price | 4.30 |
Natural Gas [Member] | Jan 1, 2017 - Apr 30, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 100,000 |
Floor Price | 2.80 |
Ceiling Price | 3.95 |
Natural Gas [Member] | May 1, 2017 - Aug 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 110,000 |
Floor Price | 2.50 |
Ceiling Price | 3.06 |
Natural Gas [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 200,000 |
Floor Price | 2.50 |
Ceiling Price | 3.27 |
Natural Gas [Member] | Jan 1, 2017 - Dec 31, 2017 [Member] | Collar [Member] | |
Derivatives, Fair Value [Line Items] | |
Average Volumes (MMBtu per month) | MMBTU / mo | 100,000 |
Floor Price | 2.60 |
Ceiling Price | 3.20 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Level 2 [Member] | Estimate of Fair Value Measurement [Member] | ||
Financial Liabilities: | ||
Notes payable | $ 86,300 | |
Recurring [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 297 | $ 9,568 |
Financial Liabilities: | ||
Commodity derivative liability | 2,874 | 0 |
Recurring [Member] | Level 1 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 0 |
Recurring [Member] | Level 2 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 297 | 9,568 |
Financial Liabilities: | ||
Commodity derivative liability | 2,874 | 0 |
Recurring [Member] | Level 3 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | $ 0 | $ 0 |
Commodity Derivative Instrume59
Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity Derivative Contracts [Member] - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Other Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | $ 2,045 | $ 6,719 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | (1,748) | (147) |
Derivative asset, Net | 297 | 6,572 |
Other Noncurrent Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | 0 | 3,354 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | 0 | (358) |
Derivative asset, Net | 0 | 2,996 |
Other Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 4,622 | 147 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | (1,748) | (147) |
Derivative liability, Net | 2,874 | 0 |
Other Noncurrent Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 0 | 358 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | 0 | (358) |
Derivative liability, Net | $ 0 | $ 0 |
Commodity Derivative Instrume60
Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Aug. 31, 2015USD ($)$ / bblbbl | Aug. 31, 2014USD ($) | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Realized gain (loss) on commodity derivatives | $ 1,577 | $ 2,355 | $ 30,466 | $ (2,138) |
Unrealized gain (loss) on commodity derivatives | 4,905 | (10,105) | 1,790 | 2,459 |
Total gain (loss) | $ 6,482 | $ (7,750) | $ 32,256 | $ 321 |
Average price of liquidated swaps (in dollars per share) | $ / bbl | 82.79 | |||
Early liquidation | $ 20,500 | |||
Number of barrels liquidated (in bbl) | bbl | 372,500 |
Commodity Derivative Instrume61
Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Monthly settlement | $ 2,331 | $ 4,396 | $ 11,212 | $ (2,138) |
Previously incurred premiums attributable to settled commodity contracts | (754) | (2,041) | (1,255) | 0 |
Early liquidation | 0 | 0 | 20,509 | 0 |
Total realized gain (loss) | $ 1,577 | $ 2,355 | $ 30,466 | $ (2,138) |
Commodity Derivative Instrume62
Commodity Derivative Instruments (Narrative) (Details) | Dec. 31, 2016counterparty |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 5 |
Credit Facility Syndicate [Member] | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 2 |
Interest Expense (Details)
Interest Expense (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Debt Instrument [Line Items] | ||||
Amortization of debt issuance costs | $ 431 | $ 1,638 | $ 853 | $ 448 |
Less: interest capitalized | (1,092) | (5,732) | (3,384) | (1,434) |
Interest expense, net | 0 | 0 | 245 | 0 |
Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest from debt | 0 | 3,940 | 0 | 0 |
Line of Credit [Member] | Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest from debt | $ 661 | $ 154 | $ 2,776 | $ 986 |
Shareholders' Equity (Common St
Shareholders' Equity (Common Stock Transactions) (Details) - USD ($) $ / shares in Units, $ in Thousands | Apr. 12, 2016 | Jan. 26, 2016 | May 31, 2016 | Apr. 30, 2016 | Jan. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 |
Classes of stock | ||||||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | ||||||||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | ||||||||
Preferred stock, shares issued | 0 | 0 | ||||||||
Preferred stock, shares outstanding | 0 | 0 | ||||||||
Common stock, shares authorized | 300,000,000 | 300,000,000 | ||||||||
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 | ||||||||
Common stock, shares issued | 110,033,601 | 200,647,572 | ||||||||
Common stock, shares outstanding | 110,033,601 | |||||||||
Sale of common stock | ||||||||||
Number of common shares sold | 22,425,000 | 16,100,000 | 51,750,000 | 0 | 90,275,000 | 18,613,952 | 0 | |||
Offering price per common share (in dollars per share) | $ 0 | $ 6.0193852119 | $ 10.75 | $ 0 | ||||||
Net proceeds | $ 164,800 | $ 89,200 | $ 289,400 | $ 0 | $ 543,400 | $ 190,845 | $ 0 | |||
Common stock issued for acquisition of mineral interests | ||||||||||
Number of common shares issued for mineral property leases | 37,051 | 0 | 995,672 | 357,901 | ||||||
Number of common shares issued for acquisitions | 4,418,413 | 0 | 4,648,136 | 872,483 | ||||||
Number of common shares sold | 4,455,464 | 0 | 5,643,808 | 1,230,384 | ||||||
Average price per common share (in dollars per share) | $ 11.28 | $ 0 | $ 10.67 | $ 9.09 | ||||||
Aggregate value of shares issued | $ 50,265 | $ 0 | $ 60,221 | $ 11,184 | ||||||
IPO [Member] | ||||||||||
Sale of common stock | ||||||||||
Number of common shares sold | 45,000,000 | 19,500,000 | 14,000,000 | |||||||
Price per share sold (in dollars per share) | $ 5.597 | $ 7.3535 | $ 5.545 | |||||||
Over-Allotment Option [Member] | ||||||||||
Sale of common stock | ||||||||||
Number of common shares sold | 6,750,000 | 2,925,000 | 2,100,000 | |||||||
Over-allotment option, exercise period | 30 days | 30 days | ||||||||
Common Stock [Member] | ||||||||||
Classes of stock | ||||||||||
Common stock, shares issued | 200,647,572 | |||||||||
Common stock, shares outstanding | 110,033,601 | 200,647,572 | 105,099,342 | 77,999,082 | 70,587,723 | |||||
Sale of common stock | ||||||||||
Number of common shares sold | 90,275,000 | 18,613,952 | ||||||||
Common stock issued for acquisition of mineral interests | ||||||||||
Number of common shares issued for mineral property leases | 37,051 | 995,672 | 357,901 | |||||||
Number of common shares issued for acquisitions | 4,418,413 | 4,648,136 | 872,483 |
Shareholders' Equity (Common 65
Shareholders' Equity (Common Stock Warrants) (Details) | 4 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2015$ / sharesshares | Dec. 31, 2016$ / sharesshares | Aug. 31, 2015$ / sharesshares | Aug. 31, 2014$ / sharesshares | Aug. 31, 2013shares | Aug. 31, 2012$ / sharesshares | Aug. 31, 2010USD ($)noteshares | Aug. 31, 2011$ / sharesshares | |
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||||
Outstanding, Beginning balance (shares) | 0 | 0 | 2,562,473 | |||||
Exercised (shares) | 0 | 0 | (2,562,473) | |||||
Forfeited / Expired (shares) | 0 | 0 | 0 | |||||
Outstanding, Ending balance (shares) | 0 | 0 | 0 | 2,562,473 | ||||
Weighted average exercise price, Beginning balance (in dollars per share) | $ / shares | $ 0 | $ 0 | $ 6 | |||||
Weighted average exercise price, exercised (in dollars per share) | $ / shares | 0 | 0 | 6 | |||||
Weighted average exercise price, forfeited/expired (in dollars per share) | $ / shares | 0 | 0 | 0 | |||||
Weighted average exercise price, Ending balance (in dollars per share) | $ / shares | $ 0 | $ 0 | $ 0 | $ 6 | ||||
Series C [Member] | ||||||||
Class of Warrant or Right [Line Items] | ||||||||
Number of warrants issued (shares) | 9,000,000 | |||||||
Number of convertible promissory note per unit | note | 1 | |||||||
Face value of promissory note | $ | $ 100,000 | |||||||
Number of shares called by each unit | 50,000 | |||||||
Number of shares of common stock per warrant | 1 | |||||||
Exercise Price (in dollars per share) | $ / shares | $ 6 | |||||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||||
Exercised (shares) | (2,561,415) | (5,938,585) | (500,000) | |||||
Series D [Member] | ||||||||
Class of Warrant or Right [Line Items] | ||||||||
Number of warrants issued (shares) | 1,125,000 | |||||||
Number of shares of common stock per warrant | 1 | |||||||
Exercise Price (in dollars per share) | $ / shares | $ 1.60 | |||||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||||
Exercised (shares) | (1,058) | (140,744) | (627,799) | |||||
Investor Relation Warrants [Member] | ||||||||
Class of Warrant or Right [Line Items] | ||||||||
Number of warrants issued (shares) | 100,000 | |||||||
Number of shares of common stock per warrant | 1 | |||||||
Exercise Price (in dollars per share) | $ / shares | $ 2.69 | |||||||
Warrant exercise period | 1 year | |||||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||||
Granted (shares) | 50,000 | |||||||
Exercised (shares) | 0 | (25,000) | (25,000) | |||||
Forfeited / Expired (shares) | (50,000) |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 4 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||||
Weighted-average shares outstanding - basic | 200,585,800 | 200,515,555 | 172,013,551 | 121,392,736 | 108,664,875 | 105,100,849 | 104,562,662 | 97,241,301 | 107,789,554 | 79,971,698 | 173,774,035 | 94,628,665 | 76,214,737 |
Potentially dilutive common shares from: | |||||||||||||
Stock options | 0 | 0 | 672,493 | 479,222 | |||||||||
Restricted stock units and stock bonus shares | 0 | 0 | 18,111 | 0 | |||||||||
Performance-vested stock units | 0 | 0 | 0 | 0 | |||||||||
Warrants | 0 | 0 | 0 | 1,114,095 | |||||||||
Weighted-average shares outstanding - diluted | 201,254,678 | 200,515,555 | 172,013,551 | 121,392,736 | 108,664,875 | 105,100,849 | 104,562,662 | 97,241,301 | 107,789,554 | 80,693,410 | 173,774,035 | 95,319,269 | 77,808,054 |
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 5,971,867 | 7,370,346,000 | 2,930,500 | 533,000 | |||||||||
Stock Options [Member] | |||||||||||||
Potentially dilutive common shares from: | |||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 5,056,000 | 6,001,500,000 | 2,785,500 | 533,000 | |||||||||
Restricted stock and stock bonus shares [Member] | |||||||||||||
Potentially dilutive common shares from: | |||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 915,867 | 890,336,000 | 145,000 | 0 | |||||||||
Performance-vested stock units [Member] | |||||||||||||
Potentially dilutive common shares from: | |||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 0 | 0 | 0 | ||||||||||
Warrants [Member] | |||||||||||||
Potentially dilutive common shares from: | |||||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 0 | 478,510,000 | 0 | 0 |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) $ in Thousands | 1 Months Ended | 4 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Dec. 31, 2015plan | Dec. 31, 2015shares | Dec. 31, 2016USD ($)shares | Aug. 31, 2015shares | Aug. 31, 2014shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of plans | plan | 3 | |||||
Unrecognized compensation expense | $ | $ 15,330 | |||||
Remaining vesting phase | 3 years 2 months 9 days | |||||
Vesting period | 5 years | |||||
Minimum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 3 years 8 months 12 days | 3 years | ||||
Maximum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 5 years | 5 years | ||||
2015 Equity Incentive Plan [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares authorized | 4,500,000 | |||||
Number of shares available for grant | 2,149,238 | |||||
Stock bonus plan [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares authorized | 2,000,000 | |||||
Restricted Stock [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation expense | $ | $ 6,711 | |||||
Remaining vesting phase | 2 years 9 months 11 days | |||||
Granted (shares) | 919,604 | 464,533 | 547,699 | 343,780 | ||
Restricted Stock [Member] | Minimum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 3 years | |||||
Restricted Stock [Member] | Maximum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period | 5 years | |||||
Performance-vested stock units [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation expense | $ | $ 2,800 | |||||
Vesting period | 3 years | |||||
Granted (shares) | 490,713 | |||||
Fair value of stock granted | $ | $ 4,000 | |||||
Performance-vested stock units [Member] | Minimum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Performance multiplier (percent) | 0.00% | |||||
Performance-vested stock units [Member] | Maximum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Performance multiplier (percent) | 200.00% |
Stock-Based Compensation (Stock
Stock-Based Compensation (Stock Based Compensation Expense) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Total stock-based compensation | $ 9,323 | $ 10,696 | $ 7,691 | $ 2,968 |
Less: stock-based compensation capitalized | (892) | (1,205) | (778) | (514) |
Total stock-based compensation expense | 8,431 | 9,491 | 6,913 | 2,454 |
Stock options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Total stock-based compensation | 2,161 | 5,417 | 4,741 | 1,767 |
Performance stock units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Total stock-based compensation | 0 | 1,047 | 0 | 0 |
Restricted stock units and stock bonus shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Total stock-based compensation | $ 7,162 | $ 4,232 | $ 2,950 | $ 1,201 |
Stock-Based Compensation (Non-Q
Stock-Based Compensation (Non-Qualified Stock Options Granted) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of options to purchase common shares | 1,142,500 | 1,067,500 | 2,377,500 | 433,000 |
Weighted-average exercise price (in dollars per share) | $ 10.84 | $ 7.19 | $ 11.55 | $ 10.37 |
Term | 10 years | 10 years | 10 years | 10 years |
Vesting Period | 5 years | |||
Fair Value | $ 6,591 | $ 3,860 | $ 13,266 | $ 3,009 |
Minimum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting Period | 3 years 8 months 12 days | 3 years | ||
Maximum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting Period | 5 years | 5 years |
Stock-Based Compensation (Sto70
Stock-Based Compensation (Stock Option Assumptions) (Details) | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expected term | 6 years 6 months | 6 years 4 months 23 days | 6 years 6 months | 6 years 8 months 12 days |
Expected volatility (percent) | 53.00% | 55.00% | 47.00% | 73.00% |
Risk-free rate, minimum (percent) | 1.80% | 1.30% | 1.40% | 1.80% |
Risk-free rate, maximum (percent) | 2.00% | 2.00% | 2.00% | 2.30% |
Expected dividend yield (percent) | 0.00% | 0.00% | 0.00% | 0.00% |
Performance-vested stock units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expected term | 2 years 8 months 26 days | |||
Expected volatility (percent) | 58.00% | |||
Weighted-average risk free rate (percent) | 0.87% |
Stock-Based Compensation (Sto71
Stock-Based Compensation (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Summary of activity for stock options (in shares): | |||||
Outstanding, Beginning balance (shares) | 4,176,500 | 5,056,000 | 2,167,000 | 1,820,000 | |
Granted (shares) | 1,142,500 | 1,067,500 | 2,377,500 | 433,000 | |
Exercised (shares) | (188,000) | (20,000) | (258,000) | (61,000) | |
Forfeited (shares) | (15,000) | (102,000) | (110,000) | (25,000) | |
Expired (shares) | (60,000) | 0 | |||
Outstanding, Ending balance (shares) | 5,056,000 | 6,001,500 | 4,176,500 | 2,167,000 | 1,820,000 |
Outstanding, Exercisable at end of period (shares) | 2,406,100 | ||||
Outstanding, Vested and expected to vest at end of period (shares) | 5,937,601 | ||||
Weighted Average Exercise Price (in dollars per share): | |||||
Beginning balance, Weighted average exercise price (in dollars per share) | $ 9.29 | $ 9.71 | $ 5.94 | $ 4.88 | |
Granted, weighted average exercise price (in dollars per share) | 10.84 | 7.19 | 11.55 | 10.37 | |
Exercised, weighted average exercise price (in dollars per share) | 6.56 | 3.91 | 3.81 | 3.71 | |
Forfeited, weighted average exercise price (in dollars per share) | 11.68 | 10.40 | 10.32 | ||
Expired, weighted average exercise price (in dollars per share) | 11.74 | 0 | 4.97 | ||
Ending balance, Weighted average exercise price (in dollars per share) | $ 9.71 | 9.27 | $ 9.29 | $ 5.94 | $ 4.88 |
Outstanding, exercisable, weighted average exercise price (in dollars per share) | 8.42 | ||||
Weighted average exercise price (in dollars per share) | $ 9.24 | ||||
Weighted-Average Remaining Contractual Life | |||||
Weighted average remaining contractual life | 8 years 7 months 25 days | 7 years 11 months 13 days | 8 years 7 months 6 days | 8 years | 8 years 8 months 12 days |
Outstanding, Exercisable | 6 years 11 months 13 days | ||||
Outstanding, Vested and expected to vest at end of period | 7 years 11 months 9 days | ||||
Aggregate Intrinsic Value: | |||||
Beginning balance, aggregate intrinsic value | $ 4,351 | $ 6,515 | $ 8,187 | $ 16,287 | $ 8,160 |
Exercised, aggregate intrinsic value | 981 | 117 | 2,103 | 481 | |
Ending balance, aggregate intrinsic value | $ 4,351 | 6,515 | $ 8,187 | $ 16,287 | $ 8,160 |
Outstanding, Exercisable at end of period | 4,297 | ||||
Outstanding, Vested and expected to vest at end of period | $ 6,511 |
Stock-Based Compensation (Issue
Stock-Based Compensation (Issued and Outstanding Option Details) (Details) - $ / shares | 4 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Outstanding options (in shares) | 6,001,500 | ||||
Weighted average remaining contractual life | 8 years 7 months 25 days | 7 years 11 months 13 days | 8 years 7 months 6 days | 8 years | 8 years 8 months 12 days |
Weighted average exercise price (in dollars per share) | $ 9.71 | $ 9.27 | $ 9.29 | $ 5.94 | $ 4.88 |
Exercisable options (in shares) | 2,406,100 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 8.42 | ||||
Under $5.00 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | $ 5 | ||||
Outstanding options (in shares) | 630,000 | ||||
Weighted average remaining contractual life | 4 years 8 months 9 days | ||||
Weighted average exercise price (in dollars per share) | $ 3.50 | ||||
Exercisable options (in shares) | 589,000 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 3.48 | ||||
$5.00 - $6.99 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | 6.99 | ||||
Exercise price range maximum (in dollars per share) | $ 5 | ||||
Outstanding options (in shares) | 1,012,000 | ||||
Weighted average remaining contractual life | 7 years 11 months 1 day | ||||
Weighted average exercise price (in dollars per share) | $ 6.38 | ||||
Exercisable options (in shares) | 430,000 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 6.51 | ||||
$7.00 - $10.99 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | 10.99 | ||||
Exercise price range maximum (in dollars per share) | $ 7 | ||||
Outstanding options (in shares) | 1,617,500 | ||||
Weighted average remaining contractual life | 8 years 5 months 19 days | ||||
Weighted average exercise price (in dollars per share) | $ 9.34 | ||||
Exercisable options (in shares) | 383,900 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 9.72 | ||||
$11.00 - $13.46 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price range minimum (in dollars per share) | 13.46 | ||||
Exercise price range maximum (in dollars per share) | $ 11 | ||||
Outstanding options (in shares) | 2,742,000 | ||||
Weighted average remaining contractual life | 8 years 4 months 24 days | ||||
Weighted average exercise price (in dollars per share) | $ 11.61 | ||||
Exercisable options (in shares) | 1,003,200 | ||||
Exercisable options, weighted average exercise price (in dollars per share) | $ 11.63 |
Stock-Based Compensation (Restr
Stock-Based Compensation (Restricted Stock and Performance-vested Stock Units Activity) (Details) - $ / shares | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Restricted Stock [Member] | ||||
Number of Shares | ||||
Nonvested, Beginning balance (shares) | 632,500 | 915,867 | 293,333 | 46,667 |
Granted (shares) | 919,604 | 464,533 | 547,699 | 343,780 |
Vested (shares) | (636,237) | (424,483) | (208,532) | (97,114) |
Forfeited (shares) | 0 | (65,581) | 0 | 0 |
Nonvested, Ending balance (shares) | 915,867 | 890,336 | 632,500 | 293,333 |
Weighted Average Grant Date Fair Value (in dollars per share) | ||||
Nonvested, beginning balance (in dollars per share) | $ 10.93 | $ 10.63 | $ 10.60 | $ 6.75 |
Granted (in dollars per share) | 10.08 | 7.66 | 11.17 | 11.34 |
Vested (in dollars per share) | 10.13 | 9.92 | 11.09 | 11.38 |
Forfeited (in dollars per share) | 0 | 8.99 | 0 | 0 |
Nonvested, ending balance (in dollars per share) | $ 10.63 | $ 9.55 | $ 10.93 | $ 10.60 |
Performance-vested stock units [Member] | ||||
Number of Shares | ||||
Nonvested, Beginning balance (shares) | 0 | |||
Granted (shares) | 490,713 | |||
Vested (shares) | 0 | |||
Forfeited (shares) | (12,203) | |||
Nonvested, Ending balance (shares) | 0 | 478,510 | ||
Weighted Average Grant Date Fair Value (in dollars per share) | ||||
Nonvested, beginning balance (in dollars per share) | $ 0 | |||
Granted (in dollars per share) | 8.10 | |||
Vested (in dollars per share) | 0 | |||
Forfeited (in dollars per share) | 8.22 | |||
Nonvested, ending balance (in dollars per share) | $ 0 | $ 8.09 |
Defined Contribution Plan (Deta
Defined Contribution Plan (Details) - USD ($) $ in Millions | Jan. 01, 2017 | Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | |||||
Percent of employer matching contribution | 100.00% | ||||
Employer matching contribution percent of employees' gross pay | 3.00% | ||||
Employer discretionary matching contribution (percent) | 50.00% | ||||
Employer discretionary contribution amount of employees' eligible compensation (percent) | 5.00% | ||||
Contribution cost recognized | $ 0.1 | $ 0.4 | $ 0.1 | $ 0.1 | |
Subsequent Event [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Percent of employer matching contribution | 100.00% | ||||
Employer matching contribution percent of employees' gross pay | 6.00% |
Income Taxes (Schedule of Compo
Income Taxes (Schedule of Components of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Current: | |||||||||||||
Federal | $ 0 | $ 106 | $ (4) | $ 4 | |||||||||
State | 0 | 0 | (111) | 111 | |||||||||
Total current income tax expense (benefit) | 0 | 106 | (115) | 115 | |||||||||
Deferred: | |||||||||||||
Federal | (45,332) | (74,099) | 10,820 | 13,748 | |||||||||
State | (4,074) | (6,651) | 972 | 1,151 | |||||||||
Total deferred income tax (benefit) expense | (49,406) | (80,750) | 11,792 | 14,899 | |||||||||
Valuation allowance | 39,399 | 80,750 | 0 | 0 | |||||||||
Income tax expense (benefit) | $ 0 | $ 5 | $ 101 | $ 0 | $ 0 | $ (10,520) | $ (2,903) | $ (709) | $ (10,007) | $ 15,802 | $ 106 | $ 11,677 | $ 15,014 |
Income Taxes (Schedule of Recon
Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||||||||||||
Federal income tax at statutory rate | $ (45,200) | $ (74,489) | $ 10,105 | $ 14,915 | |||||||||
State income taxes, net of federal tax | (4,062) | (6,685) | 908 | 1,341 | |||||||||
Statutory depletion | (150) | (287) | (451) | (1,266) | |||||||||
Stock-based compensation | 0 | 383 | 92 | 0 | |||||||||
Non-deductible compensation | 0 | 0 | 850 | 125 | |||||||||
Change in valuation allowance | 39,399 | 80,750 | 0 | 0 | |||||||||
Other | 6 | 434 | 173 | (101) | |||||||||
Income tax expense (benefit) | $ 0 | $ 5 | $ 101 | $ 0 | $ 0 | $ (10,520) | $ (2,903) | $ (709) | $ (10,007) | $ 15,802 | $ 106 | $ 11,677 | $ 15,014 |
Effective rate expressed as a percentage | 8.00% | 0.00% | 39.00% | 34.00% |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Income Tax Disclosure [Abstract] | ||
Net operating loss carryforward | $ 47,462 | $ 11,855 |
Stock-based compensation | 5,576 | 3,304 |
Basis of oil and gas properties | 62,707 | 23,656 |
Statutory depletion | 4,028 | 2,802 |
Unrealized (gain) loss on commodity derivative | 1,334 | |
Unrealized (gain) loss on commodity derivative | (2,410) | |
Other | (958) | 192 |
Deferred tax assets, gross | 120,149 | 39,399 |
Valuation allowance on tax assets | (120,149) | (39,399) |
Deferred tax asset (liability), net | $ 0 | $ 0 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Operating Loss Carryforwards [Line Items] | |
Compensation expense | $ 12.2 |
Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | 140.3 |
Net operating loss carryforwards | $ 128.1 |
Other Commitments and Conting79
Other Commitments and Contingencies (Details) | 1 Months Ended | 3 Months Ended | 4 Months Ended | 12 Months Ended | ||
Sep. 30, 2016 | Mar. 31, 2017USD ($) | Dec. 31, 2015USD ($)counterparty | Dec. 31, 2016USD ($)MMcfe | Aug. 31, 2015USD ($)counterparty | Aug. 31, 2014USD ($) | |
Long-term Purchase Commitment [Line Items] | ||||||
Transport agreement number of counterparties | counterparty | 2 | 3 | ||||
Processing plant capacity (in MMcfe) | MMcfe | 200 | |||||
Share of the commitment (in MMcfe) | MMcfe | 46.4 | |||||
Commitment term | 7 years | |||||
Transportation commitment charge | $ 2,802,000 | $ 597,000 | $ 0 | $ 0 | ||
Rent expense | $ 300,000 | 1,000,000 | $ 300,000 | $ 200,000 | ||
Denver [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Lease term | 65 months | |||||
Monthly rent expense | 50,000 | |||||
Greeley, Colorado [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Monthly rent expense | $ 7,500 | |||||
Scenario, Forecast [Member] | Denver [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Monthly rent expense | $ 62,000 |
Other Commitments and Conting80
Other Commitments and Contingencies (Volume Commitments) (Details) bbl / yr in Thousands | Dec. 31, 2016bbl / yr |
Commitments and Contingencies Disclosure [Abstract] | |
2,017 | 3,944 |
2,018 | 4,255 |
2,019 | 4,255 |
2,020 | 3,700 |
2,021 | 1,672 |
Thereafter | 0 |
Total | 17,826 |
Other Commitments and Conting81
Other Commitments and Contingencies (Minimum Lease Payments Under Non-Cancelable Operating Leases) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,017 | $ 398 |
2,018 | 840 |
2,019 | 859 |
2,020 | 878 |
2,021 | 875 |
Thereafter | 477 |
Total | $ 4,327 |
Supplemental Schedule of Info82
Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Supplemental cash flow information: | ||||
Interest paid | $ 683 | $ 3,779 | $ 2,817 | $ 989 |
Income taxes paid (refunded) | 0 | 106 | 202 | 0 |
Non-cash investing and financing activities: | ||||
Accrued well costs payable | 31,414 | 42,779 | 33,071 | 71,849 |
Assets acquired in exchange for common stock | 50 | 0 | 60 | 11 |
Obligations incurred with development activities | 1,819 | 773 | 7,051 | 1,610 |
Obligations assumed with acquisitions | 0 | 2,230 | 0 | 0 |
Obligations discharged with asset retirements and divestitures | $ 0 | $ (4,739) | $ 0 | $ 0 |
Unaudited Oil and Gas Reserve83
Unaudited Oil and Gas Reserves Information (Narrative) (Details) Boe in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015Boewell$ / bbl$ / Mcf | Dec. 31, 2016Boewell$ / bbl$ / Mcf | Aug. 31, 2015Boewell$ / bbl$ / Mcf | Aug. 31, 2014Boe$ / bbl$ / Mcf | |
Reserve Quantities [Line Items] | ||||
Net cash flows, discount rate (percent) | 10.00% | 10.00% | ||
Boe [Member] | ||||
Reserve Quantities [Line Items] | ||||
Purchase of reserves in place (Boe) | 14,207 | 55,991 | 7,860 | 2,021 |
Revisions of previous estimates (Boe) | (17,407) | (21,213) | (2,513) | 591 |
Extensions, discoveries, and other additions (Boe) | 18,647 | 3,627 | 23,696 | 17,357 |
Oil (Bbl) [Member] | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 41.33 | 36.07 | 53.27 | 89.48 |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 5.26 | |||
Gas (Mcf) [Member] | ||||
Reserve Quantities [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 2.60 | 2.44 | 3.28 | 5.03 |
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 0.16 | |||
Wattenberg Field [Member] | ||||
Reserve Quantities [Line Items] | ||||
Exploratory wells | well | 9 | 6 | 67 | |
Wattenberg Field [Member] | Boe [Member] | ||||
Reserve Quantities [Line Items] | ||||
Extensions, discoveries, and other additions (Boe) | 23,696 |
Unaudited Oil and Gas Reserve84
Unaudited Oil and Gas Reserves Information (Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015BoeMcfbbl | Dec. 31, 2016BoeMcfbbl | Aug. 31, 2015BoeMcfbbl | Aug. 31, 2014BoeMcfbbl | |
Oil (Bbl) [Member] | ||||
Proved developed and undeveloped reserves: | ||||
Beginning Balance | bbl | 27,692 | 26,379 | 16,324 | 7,047 |
Revisions of previous estimates | bbl | (10,917) | (7,788) | (1,699) | 83 |
Purchase of reserves in place | bbl | 4,380 | 23,141 | 4,201 | 1,028 |
Extensions, discoveries, and other additions | bbl | 8,263 | 1,457 | 11,465 | 9,142 |
Sale of reserves in place | bbl | (2,297) | (2,900) | (629) | (35) |
Production | bbl | (742) | (2,257) | (1,970) | (941) |
Ending Balance | bbl | 26,379 | 38,032 | 27,692 | 16,324 |
Proved developed reserves: | ||||
Proved developed reserves | bbl | 8,410 | 7,435 | 7,393 | 6,616 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | bbl | 17,969 | 30,597 | 20,299 | 9,708 |
Gas (Mcf) [Member] | ||||
Proved developed and undeveloped reserves: | ||||
Beginning Balance | Mcf | 173,958 | 238,670 | 95,179 | 40,690 |
Revisions of previous estimates | Mcf | (38,931) | (80,549) | (4,889) | 3,047 |
Purchase of reserves in place | Mcf | 58,959 | 197,103 | 21,957 | 5,956 |
Extensions, discoveries, and other additions | Mcf | 62,301 | 13,018 | 73,392 | 49,289 |
Sale of reserves in place | Mcf | (14,149) | (24,235) | (4,337) | (56) |
Production | Mcf | (3,468) | (12,086) | (7,344) | (3,747) |
Ending Balance | Mcf | 238,670 | 331,921 | 173,958 | 95,179 |
Proved developed reserves: | ||||
Proved developed reserves | Mcf | 56,751 | 62,570 | 46,026 | 38,162 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | Mcf | 181,919 | 269,351 | 127,932 | 57,017 |
Boe [Member] | ||||
Proved developed and undeveloped reserves: | ||||
Balance (Boe) | Boe | 56,685 | 66,157 | 32,188 | 13,829 |
Revisions of previous estimates (Boe) | Boe | (17,407) | (21,213) | (2,513) | 591 |
Purchase of reserves in place (Boe) | Boe | 14,207 | 55,991 | 7,860 | 2,021 |
Extensions, discoveries, and other additions (Boe) | Boe | 18,647 | 3,627 | 23,696 | 17,357 |
Sales of reserves in place (Boe) | Boe | (4,655) | (6,939) | (1,352) | (44) |
Production (Boe) | Boe | (1,320) | (4,271) | (3,194) | (1,566) |
Balance (Boe) | Boe | 66,157 | 93,352 | 56,685 | 32,188 |
Proved developed reserves: | ||||
Proved developed reserves (Boe) | Boe | 17,868 | 17,863 | 15,064 | 12,977 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves (Boe) | Boe | 48,289 | 75,489 | 41,621 | 19,211 |
Unaudited Oil and Gas Reserve85
Unaudited Oil and Gas Reserves Information (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||
Future cash inflows | $ 2,180,673 | $ 1,710,610 | $ 2,046,615 | $ 1,839,987 | |
Future production costs | (644,093) | (462,097) | (653,009) | (395,019) | |
Future development costs | (584,537) | (340,449) | (510,720) | (412,517) | |
Future income tax expense | (90,195) | (108,172) | (144,399) | (252,925) | |
Future net cash flows | 861,848 | 799,892 | 738,487 | 779,526 | |
10% annual discount for estimated timing of cash flows | (427,587) | (408,939) | (372,658) | (376,827) | |
Standardized measure of discounted future net cash flows | $ 434,261 | $ 390,953 | $ 365,829 | $ 402,699 | $ 181,732 |
Unaudited Oil and Gas Reserve86
Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details) | Dec. 31, 2016$ / bbl$ / Mcf | Dec. 31, 2015$ / bbl$ / Mcf | Aug. 31, 2015$ / bbl$ / Mcf | Aug. 31, 2014$ / bbl$ / Mcf |
Oil (Bbl) [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 36.07 | 41.33 | 53.27 | 89.48 |
Gas (Mcf) [Member] | ||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | 2.44 | 2.60 | 3.28 | 5.03 |
Unaudited Oil and Gas Reserve87
Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||
Standardized measure, beginning of year | $ 365,829 | $ 390,953 | $ 402,699 | $ 181,732 |
Sale and transfers, net of production costs | (25,222) | (81,468) | (98,486) | (86,808) |
Net changes in prices and production costs | (81,968) | (64,387) | (233,051) | 15,828 |
Extensions, discoveries, and improved recovery | 116,343 | 18,795 | 173,918 | 300,087 |
Changes in estimated future development costs | (7,195) | (6,016) | 10,002 | (20,817) |
Development costs incurred during the period | 5,923 | 62,502 | 4,957 | 15,000 |
Revision of quantity estimates | (36,820) | (110,306) | (38,340) | 4,589 |
Accretion of discount | 14,610 | 44,703 | 57,629 | 23,612 |
Net change in income taxes | 25,263 | 5,104 | 58,547 | (76,616) |
Divestitures of reserves | (43,754) | (26,839) | (19,234) | (925) |
Purchase of reserves in place | 77,024 | 228,855 | 56,795 | 47,017 |
Changes in timing and other | (19,080) | (27,635) | (9,607) | 0 |
Standardized measure, end of year | $ 390,953 | $ 434,261 | $ 365,829 | $ 402,699 |
Unaudited Quarterly Financial88
Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 4 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Aug. 31, 2015 | Aug. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||
Revenues | $ 38,695 | $ 26,234 | $ 23,947 | $ 18,273 | $ 25,448 | $ 33,378 | $ 28,286 | $ 18,938 | $ 52,931 | ||||
Expenses | 29,324 | 45,887 | 172,157 | 71,356 | 79,018 | 128,366 | 31,303 | 24,086 | $ 173,599 | 38,047 | $ 318,724 | $ 127,221 | $ 60,755 |
Operating (loss) income | 9,371 | (19,653) | (148,210) | (53,083) | (53,570) | (94,988) | (3,017) | (5,148) | (139,461) | 14,884 | (211,575) | (2,378) | 43,464 |
Other income (expense) | (4,070) | 417 | (5,537) | 1,682 | 5,383 | 6,547 | (4,474) | 3,446 | 6,522 | 27,717 | (7,508) | 32,097 | 403 |
(Loss) Income before income taxes | 5,301 | (19,236) | (153,747) | (51,401) | (48,187) | (88,441) | (7,491) | (1,702) | (132,939) | 42,601 | (219,083) | 29,719 | 43,867 |
Income tax expense (benefit) | 0 | 5 | 101 | 0 | 0 | (10,520) | (2,903) | (709) | (10,007) | 15,802 | 106 | 11,677 | 15,014 |
Net (loss) income | $ 5,301 | $ (19,241) | $ (153,848) | $ (51,401) | $ (48,187) | $ (77,921) | $ (4,588) | $ (993) | $ (122,932) | $ 26,799 | $ (219,189) | $ 18,042 | $ 28,853 |
Net (loss) income per common share: | |||||||||||||
Basic (in dollars per share) | $ 0.03 | $ (0.10) | $ (0.89) | $ (0.42) | $ (0.44) | $ (0.74) | $ (0.04) | $ (0.01) | $ (1.14) | $ 0.34 | $ (1.26) | $ 0.19 | $ 0.38 |
Diluted (in dollars per share) | $ 0.03 | $ (0.10) | $ (0.89) | $ (0.42) | $ (0.44) | $ (0.74) | $ (0.04) | $ (0.01) | $ (1.14) | $ 0.33 | $ (1.26) | $ 0.19 | $ 0.37 |
Weighted-average shares outstanding: | |||||||||||||
Basic (in shares) | 200,585,800 | 200,515,555 | 172,013,551 | 121,392,736 | 108,664,875 | 105,100,849 | 104,562,662 | 97,241,301 | 107,789,554 | 79,971,698 | 173,774,035 | 94,628,665 | 76,214,737 |
Diluted (in shares) | 201,254,678 | 200,515,555 | 172,013,551 | 121,392,736 | 108,664,875 | 105,100,849 | 104,562,662 | 97,241,301 | 107,789,554 | 80,693,410 | 173,774,035 | 95,319,269 | 77,808,054 |
Subsequent Events (Details)
Subsequent Events (Details) a in Thousands, $ in Millions | Feb. 04, 2016USD ($) | Jan. 31, 2017USD ($)aBoe | Oct. 31, 2016USD ($) | Aug. 31, 2016USD ($) | Dec. 31, 2015Boe | Dec. 31, 2016Boe | Aug. 31, 2015Boe | Aug. 31, 2014Boe |
Subsequent Event [Line Items] | ||||||||
Production of BOE (in Boe's) | Boe | 1,320,000 | 4,271,000 | 3,194,000 | 1,566,000 | ||||
Series of Individually Immaterial Business Acquisitions [Member] | ||||||||
Subsequent Event [Line Items] | ||||||||
Total purchase price | $ 10 | $ 9.6 | $ 3.9 | |||||
Subsequent Event [Member] | Series of Individually Immaterial Business Acquisitions [Member] | ||||||||
Subsequent Event [Line Items] | ||||||||
Total purchase price | $ 25 | |||||||
Subsequent Event [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | ||||||||
Subsequent Event [Line Items] | ||||||||
Mineral acres, net | a | 10 | |||||||
Production of BOE (in Boe's) | Boe | 700 | |||||||
Proceeds from sale of assets | $ 71 |